Excelerate Energy Annual Report 2015

← All annual reports

FY2015 Annual Report · Excelerate Energy

Loading PDF…

2015 Annual Report

2015
Board of Directors & Officers

Officers

Mary E. Kipp
Chief Executive Officer

Steven T. Buraczyk
Senior Vice President
Operations

Nathan T. Hirschi
Senior Vice President
and Chief Financial Officer

Rocky R. Miracle
Senior Vice President
Corporate Services and Chief Compliance Officer

William A. Stiller
Senior Vice President
Public and Customer Affairs and Chief Human Resources Officer

John R. Boomer
Senior Vice President
and General Counsel

Robert C. Doyle
Vice President
Transmission and Distribution
and System Planning

Russell G. Gibson
Vice President
Controller

Eduardo Gutiérrez
Vice President
Public, Government and Customer Affairs

David C. Hawkins
Vice President
System Operations, Resource Planning and Management

Kerry B. Lore
Vice President
Customer Care

Andres R. Ramirez
Vice President
Power Generation

Guillermo Silva, Jr.
Vice President
Community Outreach

H. Wayne Soza
Vice President
Compliance and Chief Risk Officer

Richard E. Turner
Vice President
Renewables Development

Board of Directors

Charles A. Yamarone
Chairman of the Board / El Paso Electric Company
Chief Corporate Governance and Compliance Officer
Houlihan Lokey
Los Angeles, CA

Edward Escudero
Vice Chairman of the Board / El Paso Electric Company
President and Chief Executive Officer
High Desert Capital, LLC
El Paso, TX

Catherine A. Allen
Founder, Chairman and Chief Executive Officer
The Santa Fe Group
Santa Fe, NM

J. Robert Brown
Owner and President
Brownco Capital, LLC
El Paso, TX

James W. Cicconi
Senior Executive Vice President
External and Legislative Affairs, AT&T Services, Inc.
Washington, D.C.

James W. Harris
Managing Partner / OP Food Products, LLC and
Harris Financial Advisors, LLC
Manns Harbor, NC

Patricia Z. Holland-Branch
Owner, Chairman and Chief Executive Officer
The Facilities Connection, Inc.
El Paso, TX

Woodley L. Hunt
Executive Chairman
Hunt Companies, Inc.
El Paso, TX

Mary E. Kipp
Chief Executive Officer
El Paso Electric Company
El Paso, TX

Thomas V. Shockley, III
Retired Chief Executive Officer
El Paso Electric Company
Dallas, TX

Eric B. Siegel
Retired Limited Partner of Apollo Advisors, LP
Consultant and Special Advisor to the
Chairman of the Milwaukee Brewers Baseball Club
Los Angeles, CA

Stephen N. Wertheimer
Managing Director and Founding Partner
W Capital Partners
New York, NY

In 2015, as it has done throughout its 115-year history, the El Paso Electric Company (“EE” or the “Company”) delivered

clean, safe, reliable and affordable electricity to our customers in the west Texas and southern New Mexico region.

Our dedicated team of more than 1,000 employees was able to build upon past successes and foster a culture which

will enable the Company to continue to excel in the areas of safety, reliability and customer satisfaction for years to come.

In recent years, our region has experienced solid growth driven by increased investment from both the private and public

sectors, and we currently are required to deliver electric power to over 400,000 customers. Accordingly, we have taken

many steps to meet the growing and changing needs of our customers, while maintaining and enhancing the safety,

security and reliability of our system. Since 2009, the growth throughout our service territory has led the Company

to invest close to $1.3 billion in new generation assets, expanded transmission and distribution capabilities, and grid

modernization equipment, including investments to enhance the cybersecurity of our system.

This substantial capital outlay includes the recently completed Montana Power Station (“MPS”) Units 1 & 2, the Eastside

Operations Center, and new transmission and distribution lines. During this period, EE added over 545 megawatts

of new and more efficient local generating facilities to its system. These additions will allow us to meet the growing

demands being placed on our system, and also will serve to replace generation units that are at or near the end of their

useful lives. For example, we are excited by the prospect of becoming a coal-free utility in July of 2016 when we sell

our 7% ownership interest in Units 4 and 5 at the Four Corners Generating Station, a sale made possible by our

commitment to build local generating capacity.

As a result of these investments, the Company filed significant rate cases in Texas and New Mexico during 2015

to ensure that customers were charged rates which were fair and reasonable in light of the Company’s substantial

commitments of capital since the prior rate cases. These requested increases are integral to maintaining the Company’s

financial strength and stability. The decline in earnings per share during 2015 by more than 10% to $2.03 per share from

$2.27 per share in 2014 highlights the need for appropriate and timely rate recovery to ensure that we can continue

to fulfill our commitments to customers and shareholders alike.

In the Texas rate case, the Company has reached a settlement with the majority of the parties on most of the issues,

including the Company’s future revenue requirement. We believe that our commitment to establish and maintain a

credible and open dialogue with all affected stakeholders facilitated the settlement of the Texas case. A final order is

expected in Texas later this year. In New Mexico, the rate case went through a contested hearing process, and EE

is awaiting the final order from the New Mexico Public Regulation Commission. As these cases develop, we will

continue to communicate with all stakeholders in an open and transparent manner.

Looking to the future, as west Texas and southern New Mexico continue to grow, the Company will need to add additional

generating capacity and upgrade existing infrastructure. We currently expect to invest an additional $1.1 billion over the

next five years. Slightly less than half of these future capital expenditures are earmarked for additional generation capacity.

Our new generating units will also enhance operational flexibility due to their quick start and cycling capabilities. This ability

to respond promptly to changes in our system’s supply and demand is critical to our ability to lead the electric utility

industry in the deployment of solar generating capacity, including our current portfolio of large-scale solar generation as

well as the additional 8 megawatts of large-scale solar resources currently under consideration.

In 2016 alone, the Company plans to add two additional 88 megawatt gas-fired units at MPS, and will begin preparing

the rate cases needed to recover these and other investments. EE currently expects to file rate cases in New Mexico

and Texas in early 2017. The Company’s current capital investment and rate recovery plans have been communicated

to our regulators and our other stakeholders to ensure transparency and collaboration at the earliest stages of the

rate-making process.

As we face the challenges and changes that lay ahead for our region and our industry, we remain committed to safely

and reliably serving our customers while providing long-term value to our shareholders. The people of the El Paso Electric

Company have focused their talents on providing clean, safe, reliable and affordable electricity to the Company’s

customers for over one hundred years. We are committed to continuing this proud tradition in the coming years as our

region and the electric utility industry both continue to grow and evolve.

In closing, we also note that 2015 marked another turning point for our Company when Tom Shockley retired as our

Chief Executive Officer. We would like to extend our gratitude to Tom for his outstanding leadership during his three-year

tenure as our CEO. Tom’s leadership and foresight strengthened our relationships with our customers and regulators,

while enabling our Board to develop and execute a successful management transition plan. We look forward to working

with Tom going forward as a valued member of our Board of Directors.

Thank you for your continued confidence in the El Paso Electric Company.

Charles A. Yamarone
Chairman of the Board of Directors

Mary E. Kipp
Chief Executive Officer

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

(Mark One)

_______________________

Form 10-K

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

For the fiscal year ended December 31, 2015

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
(State or other jurisdiction
of incorporation or organization)

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

74-0607870
(I.R.S. Employer
Identification No.)

79901
(Zip Code)

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

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

Title of each class
Common Stock, No Par Value

Name of each exchange on which registered
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

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

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

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

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.

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

Accelerated filer

Non-accelerated filer

(Do not check if a smaller reporting company)

Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES

As of June 30, 2015, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,380,612,681 (based

on the closing price as quoted on the New York Stock Exchange on that date).

As of January 31, 2016, there were 40,483,000 shares of the Company’s no par value common stock outstanding.

Portions of the registrant’s definitive Proxy Statement for the 2016 annual meeting of its shareholders are incorporated by reference

DOCUMENTS INCORPORATED BY REFERENCE

into Part III of this report.

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

DEFINITIONS

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.......................................
HAFB ................................................. Holloman Air Force Base
IRS......................................................
Internal Revenue Service

Four Corners Generating Station

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..................................................
RGEC .................................................

Public Utility Commission of Texas

Rio Grande Electric Cooperative

RGRT..................................................

Rio Grande Resources Trust

TEP.....................................................
White Sands........................................ White Sands Missile Range

Tucson Electric Power Company

(i)

TABLE OF CONTENTS

Item

Description

PART I
1 Business .......................................................................................................................................................................
1A Risk Factors .................................................................................................................................................................
1B Unresolved Staff Comments ........................................................................................................................................
2 Properties .....................................................................................................................................................................
3 Legal Proceedings ........................................................................................................................................................
4 Mine Safety Disclosures ..............................................................................................................................................

Page

1
15
20
20
20
20

PART II
5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ...
21
6 Selected Financial Data ................................................................................................................................................
24
7 Management’s Discussion and Analysis of Financial Condition and Results of Operations .......................................
25
7A Quantitative and Qualitative Disclosures About Market Risk .....................................................................................
44
8 Financial Statements and Supplementary Data ............................................................................................................
46
9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ....................................... 105
9A Controls and Procedures .............................................................................................................................................. 105
9B Other Information ........................................................................................................................................................ 105

PART III ................................................................................................................................................................. 105

PART IV

................................................................................................................................................................. 105

(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 by the Company's discussion of strategies or trends. Forward-looking statements describe our
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 our regulators,

our ability to fully and timely recover our costs and earn a reasonable rate of return on our invested capital
through the rates that we are permitted to charge,

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

the ability of our operating partners to maintain plant operations and manage operation and maintenance
costs at the Palo Verde and Four Corners plants, including costs to comply with any new or expanded
regulatory or environmental requirements,

reductions in output at generation plants operated by us,

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

our reliance on significant customers,

the credit worthiness of our customers,

unscheduled outages of generating units including outages at Palo Verde,

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

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

(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 our nuclear decommissioning liability for
Palo Verde, as well as actual and assumed investment returns on decommissioning trust fund assets,

disruptions in our transmission system, and in particular the lines that deliver power from our remote
generating facilities,

electric utility deregulation or re-regulation,

regulated and competitive markets,

ongoing municipal, state and federal activities,

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

political, legislative, judicial and regulatory developments,

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

changes in environmental laws and regulations and the enforcement or interpretation thereof, including
those related to air, water or greenhouse gas ("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 us,

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, our ability to recruit and retain qualified employees and our ability to successfully
implement succession planning, and

other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is
included in this document under the headings "Risk Factors" and "Management’s Discussion and Analysis" "–Summary of Critical
Accounting Policies and Estimates" and "–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 we are not obligated to update any forward-looking statement to reflect events or circumstances after
the date on which such statement was made, except as required by applicable laws or regulations.

(iv)

Item 1.

Business

PART I

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 2,055 MW. For the year ended
December 31, 2015, the Company’s energy sources consisted of approximately 47% nuclear fuel, 34% natural gas, 6% coal, 13%
purchased power and less than 1% generated by Company-owned solar photovoltaic panels and wind turbines. The Company
continues to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. As of December 31,
2015, the Company has power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy
Sources- Purchased Power").

The Company serves approximately 404,500 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 63% and 12%, respectively, of the Company’s retail revenues for the year ended December 31, 2015). 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, including 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, 2016, 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 the Annual Report 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.

As of December 31, 2015, the Company’s net dependable generating capability of 2,055 MW consists of the following:

Facilities

Station
Newman Power Station
Palo Verde
Rio Grande Power Station
Montana Power Station (Units 1 and 2)

Four Corners (Units 4 and 5)
Copper Power Station

Renewables
Total

Primary Fuel
Type
Natural Gas
Nuclear
Natural Gas
Natural Gas
Coal
Natural Gas

Wind/Solar

Company's
Share of Net
Dependable
Generating
Capability *
(MW)

Company
Ownership
Interest

Location
El Paso, Texas

100.0%
15.8% Wintersburg, Arizona
100% Sunland Park, New Mexico
100%

El Paso, Texas

7% Fruitland, New Mexico

100%

El Paso, Texas
Hudspeth/El Paso Counties,
Texas; Dona Ana County,
New Mexico

752
633
321
176
108
64

1
2,055

____________________
* During summer peak period, the Company owned renewables include a wind ranch with a total capacity of 1.32 MW

and six solar photovoltaic facilities with a total capacity of 0.2 MW.

Palo Verde

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

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

• Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its
share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities,
through the term of their respective operating licenses. In 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, 2015, the Company's decommissioning trust fund had a balance of $239.0 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.

•

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 million by the DOE to the Palo Verde Participants for certain specified costs incurred by
Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received
approximately $9.1 million, representing its share of the award. The majority of the award was 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. The majority of the award was credited to customers through the applicable fuel adjustment clauses in
March 2015. Thereafter APS will file annual claims for the period July 1 of the then-previous year to June 30
of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014
through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. Funds related to
this claim are expected to be received in the second quarter of 2016. The Company's share of this claim is
approximately $1.9 million.

• 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 at 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
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.

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 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 August
2014 final rule has been subject to continuing legal challenges before the NRC and the Court of Appeals.

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.

• 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.

but has minor additional work to perform in 2016. Palo Verde has spent approximately $125 million (the
Company's share is $19.7 million) on capital enhancements related to these requirements as of December 31,
2015.

• 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 $2.8 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 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 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 two aeroderivative generating units which operate on natural

gas.

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

The Company owns a 7% interest in Units 4 and 5 at Four Corners. The Company shares power entitlements and certain
allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. Four Corners
is a coal-fired generating facility that is located on land under easements from the federal government and a lease from the Navajo
Nation that expires in July of 2016. APS, on behalf of the Four Corners participants, negotiated amendments to the lease with the
Navajo Nation which extended the lease from 2016 to 2041.

The Company notified the other participants in 2013 that it would not continue in Four Corners after the termination of the
50-year contractual term of the participation agreement in July 2016 but that it would offer to sell its interest to them in order to
facilitate their decision to extend the life of the plant. On February 17, 2015, the Company and APS entered into an asset purchase
agreement (the "Purchase and Sale Agreement") providing for the purchase by APS of the Company’s interests in Four Corners.
The cash purchase price is equal to the net book value of the Company’s interest in Four Corners at the date of closing. The
anticipated closing date for the sale is July 6, 2016, pending regulatory approval. The purchase price will be adjusted downward
to reflect APS’s assumption in the Agreement of the Company’s obligation to pay for future plant decommissioning and mine
reclamation expenses. At the closing, APS will also reimburse the Company for the undepreciated value of certain capital
expenditures made prior thereto. APS will assume responsibility for all capital expenditures made after July 2016 and, with certain
exceptions, any pre-2016 capital expenditures to be put into service following the closing. In addition, APS will indemnify the
Company against liabilities and costs related to the future operation of Four Corners.

Wind and Solar Photovoltaic Facilities

The Company’s Hueco Mountain Wind Ranch consists of two wind turbines with a total capacity of 1.32 MW. 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 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)

Springerville-Macho Springs-Luna-Diablo Line (1)

West Mesa-Arroyo Line (2)

Greenlee-Hidalgo-Luna-Newman Line (3)

Greenlee-Hidalgo

Hidalgo-Luna

Luna-Newman

Eddy County-AMRAD Line (4)

Palo Verde Transmission

Palo Verde-Westwing (5)

Palo Verde-Jojoba-Kyrene (6)

310

202

125

345

500

Company
Ownership
Interest

100.0%

40.0%

57.2%

100.0%

66.7%

18.7%

____________________
(1) Runs from Tucson Electric Power Company ("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 near Duncan, Arizona to the Newman Power Station.
(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.

Environmental Matters

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.

See Part II, Item 8, Financial Statements and Supplementary Data, Note K for more information regarding environmental

risks, laws and regulations and legal proceedings for which we are and maybe subject to in the future.

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.

The Company’s estimated cash construction costs for 2016 through 2020 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)

2016................................................... $
2017...................................................
2018...................................................
2019...................................................
2020...................................................

Total ........................................... $

231
156
182
232
283
1,084

By Function
(estimates in millions)

Production (1)(2) ........................ $
Transmission...............................
Distribution .................................
General........................................

534
113
323
114

Total..................................... $

1,084

__________________________
(1) Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel."
(2) Estimated production costs consist of:

$307 million for new generating capacity, including:

ii.

iii.

$32 million for MPS of which $25 million is to complete construction of two 88 MW gas-fired
LMS-100 units (3 and 4) that are scheduled to come on line in May and December of 2016,
respectively.
$254 million of construction costs from 2018 through 2020 for two combined cycle units scheduled
to be completed in 2022 and 2024.
$21 million for two utility-scale solar energy generating facilities, which would have a combined
maximum capacity up to 8 MW.

$227 million of other generation costs, including $189 million for Palo Verde.

General

Energy Sources

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.

Years Ended December 31,

Power Source
Nuclear .................................................................
Natural gas............................................................
Coal ......................................................................
Purchased power ..................................................
Total...............................................................

2015

2013

2014
(percentage of energy mix)
47%
34
6
13
100%

47%
35
5
13
100%

46%
34
6
14
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 "– 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 2019-2021. The participants have
also contracted for 100% of Palo Verde's enrichment services through 2020 and all of Palo Verde's fuel assembly fabrication
services through 2022.

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. 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 revolving credit facility (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 2015, the Company’s natural
gas requirements at the 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 2016. 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 the Newman and Copper Power Stations is also supplied pursuant to a long-term intrastate natural gas contract

that became effective October 1, 2009 and continues through 2017.

Coal

APS, as operating agent for Four Corners, purchases Four Corners' coal requirements from a supplier with a long-term lease

of coal reserves owned by the Navajo Nation.

On December 30, 2013, APS and Southern California Edison ("SCE") closed their previously announced transaction whereby
APS agreed to purchase SCE's 48% interest in Units 4 and 5 of Four Corners. Concurrently with the closing of this transaction,
the ownership of BHP Navajo Coal Company, the coal supplier and operator of the mine that serves Four Corners, was transferred
to Navajo Transitional Energy Company, LLC ("NTEC"), a company formed by the Navajo Nation to own the mine and develop
other energy projects.

The Company notified the other participants in 2013 that it would not continue in Four Corners after the termination of the
50-year contractual term of the participation agreement in July 2016 but that it would offer to sell its interest to them in order to
facilitate their decision to extend the life of the plant. On February 17, 2015, the Company and APS entered into the Purchase and
Sale Agreement providing for the purchase by APS of the Company’s interests in Four Corners. The cash purchase price is equal
to the net book value of the Company’s interest in Four Corners at the date of closing. The anticipated closing date for the sale is
July 6, 2016, pending regulatory approval. The purchase price will be adjusted downward to reflect APS’s assumption in the
Agreement of the Company’s obligation to pay for future plant decommissioning and mine reclamation expenses. At the closing,
APS will also reimburse the Company for the undepreciated value of certain capital expenditures made prior thereto. APS will
assume responsibility for all capital expenditures made after July 2016 and, with certain exceptions, any pre-2016 capital
expenditures to be put into service following the closing. In addition, APS will indemnify the Company against liabilities and
costs related to the future operation of Four Corners.

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 with Freeport-McMoran Copper and 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 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 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 under the agreement. The parties have agreed to increase the amount to 125 MW through
December 2016.

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 of approximately 10 MW from a solar photovoltaic generation plant on land subleased
from the Company in proximity to its Newman Generation Station. This solar project began commercial operation in December
2014.

Other purchases of shorter duration were made during 2015 to supplement the Company's generation resources during planned

and unplanned outages, for economic reasons, and to supply off-system sales.

Operating Statistics

Operating revenues (in thousands):
Non-fuel base revenues:

Retail:

Residential..................................................................................... $
Commercial and industrial, small .................................................
Commercial and industrial, large ..................................................
Sales to public authorities .............................................................
Total retail base revenues.......................................................

Wholesale:

Sales for resale ..............................................................................
Total non-fuel base revenues .................................................

Fuel revenues:

Recovered from customers during the period.........................................
Under (over) collection of fuel ...............................................................
New Mexico fuel in base rates................................................................
Total fuel revenues........................................................................

Off-system sales:

Fuel cost..................................................................................................
Shared margins .......................................................................................
Retained margins ....................................................................................
Total off-system sales....................................................................
Other ..............................................................................................................

Total operating revenues........................................................ $

Number of customers (end of year) (1):

Residential......................................................................................................
Commercial and industrial, small ..................................................................
Commercial and industrial, large...................................................................
Other ..............................................................................................................
Total .......................................................................................
Average annual kWh use per residential customer ...............................................
Energy supplied, net, kWh (in thousands):

Years Ended December 31,
2014

2013

2015

246,265
187,436
40,411
91,244
565,356

2,455
567,811

127,765
(13,342)
72,129
186,552

52,406
11,048
1,362
64,816
30,690
849,869

358,819
40,367
49
5,261
404,496
7,763

234,371
185,388
39,239
92,066
551,064

2,277
553,341

161,052
3,110
71,614
235,776

74,716
21,117
2,147
97,980
30,428
917,525

353,885
40,038
49
5,017
398,989
7,496

236,651
184,568
40,235
95,044
556,498

2,172
558,670

133,481
10,849
73,295
217,625

68,241
13,016
1,549
82,806
31,261
890,362

349,629
39,164
50
5,043
393,886
7,701

Generated .......................................................................................................
Purchased and interchanged...........................................................................
Total .......................................................................................

9,585,089
1,390,946
10,976,035

9,477,129
1,390,490
10,867,619

9,288,773
1,547,930
10,836,703

Energy sales, kWh (in thousands):

Retail:

Residential ..............................................................................................
Commercial and industrial, small ...........................................................
Commercial and industrial, large............................................................
Sales to public authorities.......................................................................
Total retail .....................................................................................

Wholesale:

Sales for resale........................................................................................
Off-system sales......................................................................................
Total wholesale..............................................................................
Total energy sales...................................................................
Losses and Company use ...............................................................................
Total .......................................................................................

2,771,138
2,384,514
1,062,662
1,585,568
7,803,882

63,347
2,500,947
2,564,294
10,368,176
607,859
10,976,035

Native system:

Peak load, kW ................................................................................................
Net dependable generating capability for peak, kW......................................

1,794,000
2,055,000

Total system:

Peak load, kW (2) ..........................................................................................
Net dependable generating capability for peak, kW......................................

1,992,000
2,055,000

2,640,535
2,357,846
1,064,475
1,562,784
7,625,640

61,729
2,609,769
2,671,498
10,297,138
570,481
10,867,619

1,766,000
1,879,000

1,953,000
1,879,000

2,679,262
2,349,148
1,095,379
1,622,607
7,746,396

61,232
2,472,622
2,533,854
10,280,250
556,453
10,836,703

1,750,000
1,852,000

1,883,000
1,852,000

___________________________
(1)
(2)

The number of retail customers presented is based on the number of service locations.
Includes spot sales and net losses of 198,000 kW, 187,000 kW and 133,000 kW for 2015, 2014 and 2013, respectively.

General

Regulation

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

2012 Texas Retail Rate Case. On April 17, 2012, the El Paso City Council approved the settlement of the Company's 2012
Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094. The PUCT issued a final order approving the settlement
on May 23, 2012 and the rates were effective as of May 1, 2012. As part of the 2012 Texas retail rate settlement, the Company
agreed to submit a future fuel reconciliation request covering the period beginning July 1, 2009 and ending no later than June 30,
2013 by December 31, 2013 or as part of its next rate case, if earlier. The Company filed a fuel reconciliation request covering
the period July 1, 2009 through March 31, 2013, as discussed below. The 2012 Texas retail rate settlement also provided for the
continuation of the energy efficiency cost recovery factor and the military base discount recovery factor. Both of these surcharges
require annual filings to reconcile and revise the recovery factors.

2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities
incorporated in its Texas service territory, and the PUCT in Docket No. 44941, a request for an increase in non-fuel base revenues
of approximately $71.5 million. The request includes recovery of new plant placed into service since 2009 . On January 15, 2016,
the Company filed its rebuttal testimony modifying the requested increase to $63.3 million. The Company has invoked its statutory
right to have its new rates relate back for consumption on and after January 12, 2016, which is the 155th day after the filing. The
difference in rates that would have been collected will be surcharged or refunded to customers beginning after the PUCT's final
order in Docket No. 44941, which is expected to be in the second quarter of 2016. The PUCT has the authority to require the
Company to surcharge or refund such difference over a period not to exceed 18 months. On January 21, 2016, the Company, the
City of El Paso, the PUCT staff, the Office of Public Utility Counsel and the Texas Industrial Energy Consumers filed a joint
motion to abate the procedural schedule to facilitate settlement talks. This motion was granted. The Company cannot predict the
outcome of the rate case at this time.

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

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

Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered
from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows
the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon
the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires
the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount
and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to
surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery
to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the
previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT
in fuel reconciliation proceedings.

On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor
by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the PUCT's
materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the

PUCT on May 20, 2015. As of December 31, 2015, the Company had over-recovered fuel costs in the amount of $0.1 million for
the Texas jurisdiction.

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

Montana Power Station Approvals. The Company has received a Certificate of Convenience and Necessity ("CCN") from
the PUCT to construct four natural gas fired generating units at MPS in El Paso County, Texas. The Company also obtained air
permits from the Texas Commission on Environmental Quality (the "TCEQ") and the U.S. Environmental Protection Agency (the
"EPA"). MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in
March 2015.

Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program to
include construction and ownership of a 3 MW solar photovoltaic system located at MPS. Participation will be on a voluntary
basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT
Docket No. 44800. The Company presented the other parties a proposed structure for settlement of this proceeding and the other
parties are in the process of evaluating it.

Four Corners. On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for
the purchase by APS of the Company's interests in Four Corners. The Purchase and Sale Agreement included a projected cash
purchase price which will be equal to the net book value of our interest in Four Corners at the date of close. The net book value
at June 30, 2016 is expected to approximate $20 million. The Company will also be reimbursed for certain undepreciated capital
expenditures, that are projected to approximate $10 million at June 30, 2016. The purchase price will be adjusted downward to
reflect APS's assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses
estimated at July 6, 2016 to be $7.0 million and $19.3 million, respectively.

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. The anticipated closing date of the sale is July
6, 2016, pending regulatory approval. This case was assigned PUCT Docket No. 44805. It is expected that the final coal mine
closing and reclamation costs, which the Company historically has been permitted to recover in its fuel recovery mechanism, will
be addressed in the proceeding, as well as other issues related to post-participation events such as the ARO. On January 11, 2016,
the PUCT referred the case to the State Office of Administrative Hearings ("SOAH") for an administrative hearing. On February
5, 2016, an administrative law judge ("ALJ") of the SOAH issued an order adopting a procedural schedule. The procedural schedule
calls for a hearing on the merits to be held in the fourth quarter of 2016. At December 31, 2015 the regulatory asset associated
with mine reclamation costs for our Texas jurisdiction approximates $7.6 million. At the PUCT's February 11, 2016 open meeting,
Commissioners discussed whether the Company's application should be addressed in a rate case. On February 11, 2016, the PUCT
issued its Order Requesting Briefing on Threshold Legal/Policy Issues, seeking briefs from the parties on the issue "Should the
Commission dismiss this docket?" Such briefs were due by February 22, 2016. The PUCT is expected to consider that issue at its
open meeting currently scheduled for March 3, 2016.

The Company currently continues to recover its mine reclamation costs in Texas under previous orders and decisions of the
PUCT. If any future determinations made by our regulators result in changes to how existing regulatory assets or previously
incurred costs for Four Corners are recovered in rates, any such changes would be recognized only when it becomes probable
future cash flows will change as a result of such regulatory actions.

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

Public Utility Regulatory Act (the "PURA") and the PUCT.

New Mexico Regulatory Matters

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

plant placed into service since the last time rates were adjusted in 2009. The filing also requests an annual reduction of $15.4
million, or 21.5%, for fuel and purchased power costs recovered in base rates. The reduction in fuel and purchased power rates
reflects reduced fuel prices and improvements in system heat rates due to new generating unit additions. Subsequently, the Company
reduced its requested increase in non-fuel base rates to approximately $6.4 million On February 16, 2016, the Hearing Examiner
issued a Recommended Decision to the NMPRC proposing an annual increase in non-fuel base rates of approximately $640
thousand. On February 17, 2016, the NMPRC issued an order extending the suspension period in the rate case from March 10,
2016 until April 8, 2016, by which time the NMPRC is expected to either issue a final order with new rates to go into effect in the
second quarter of 2016 or again extend the suspension period further to as late as June 10, 2016. All parties will be allowed to file
exceptions before the NMPRC ultimately rules on the issues by final order. The Company cannot predict the outcome of the rate
case at this time.

Fuel and Purchased Power Costs. Fuel and purchased power costs are recovered through base rates and a Fuel and Purchased
Power Cost Adjustment Clause (the "FPPCAC") that accounts for changes in the costs of fuel relative to the amount included in
base rates. On January 8, 2014, the NMPRC approved the continuation of the FPPCAC without modification in NMPRC Case
No. 13-00380-UT. Fuel and purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded
to customers the second succeeding month. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New
Mexico through the FPPCAC as purchased power using a proxy market price approved in the 2014 FPPCAC continuation. At
December 31, 2015, we had a net fuel over-recovery balance of $3.8 million in New Mexico.

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

Four Corners Generating Station ("Four Corners"). On February 17, 2015, the Company and APS entered into the Purchase
and Sale Agreement providing for the purchase by APS of the Company's interests in Four Corners. On April 27, 2015, the Company
filed an application requesting all necessary regulatory approvals to sell its ownership interest in Four Corners. The anticipated
closing date of the sale is July 6, 2016, pending regulatory approval. This case was assigned NMPRC Case No. 15-00109-UT.
On February 2, 2016, the Company filed a joint stipulation with the NMPRC reflecting a settlement agreement among the
Commission Utility Division Staff, the Company and the New Mexico Attorney General proposing approval of abandonment and
sale of its seven percent minority ownership interest in Four Corners Units 4 and 5 and common facilities to APS. An addendum
to the joint stipulation was subsequently filed to include non-opposition by other non-stipulating parties. A hearing in the case was
held on February 16, 2016, and a final order approving the joint stipulation is expected in the first half of 2016. Based on the joint
stipulation and addendum, no significant gain or loss is expected to be realized upon closing of the sale.

5 MW HAFB Facility CCN. On June 15, 2015, the Company filed a petition with the NMPRC requesting CCN authorization
to construct a 5 MW solar-powered generation facility to be located at HAFB in the Company's service territory in New Mexico.
The new facility will be a dedicated Company-owned resource serving HAFB. This case was assigned NMPRC Case No. 15-00185-
UT. On October 7, 2015, the NMPRC issued a Final Order accepting the Hearing Examiner’s Recommended Decision to approve
the CCN, as modified, that the Company shall not seek to recover any revenue requirement associated with the facility from New
Mexico jurisdictional customers other than HAFB without prior NMPRC approval.

Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case
No. 15-00280-UT to issue up to $310 million in new long-term debt; and to guarantee the issuance of up to $65 million of new
debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval
supersedes prior approvals.

Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions,

recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC.

Federal Regulatory Matters

Four Corners. On June 26, 2015, APS filed an application requesting authorization from FERC to purchase 100% of the
Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and
rights. On December 22, 2015, FERC issued an order approving the proposed transaction.

PNM Transmission Rate Case. On December 31, 2012, PNM filed with FERC to change its method of transmission rate
recovery for its transmission delivery services from stated rates to formula rates. The Company takes transmission service from
PNM and is among the PNM transmission customers affected by PNM’s shift to formula rates. On March 1, 2013, the FERC
issued an order rejecting in part PNM’s filing, and establishing settlement judge and hearing procedures. On March 20, 2015,
PNM filed with FERC a settlement agreement and offer of settlement resolving all issues set for hearing in the proceeding. On
March 25, 2015, the Chief Judge issued an order granting PNM's motion to implement the settled rates. However, the Company
is still awaiting a final decision from the FERC on whether the settlement will be approved. The Company cannot predict the
outcome of the case at this time.

Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an
order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under its existing revolving credit
facility up to $400 million outstanding at any time, to issue up to $310 million in long-term debt, and to guarantee the issuance of
up to $65 million of new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from
November 15, 2015 through November 15, 2017. This approval supersedes prior approvals.

Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and

other approvals as required by the FERC.

Department of Energy. The DOE regulates the Company's exports of power to the Comisión Federal de Electricidad in

Mexico pursuant to a license and two presidential 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 2015.

Franchises and Significant Customers

Franchises

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

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

Military Installations

The Company serves HAFB, White Sands and Fort Bliss. The military installations represent approximately 4% of the
Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss for an initial three-year term
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 March 2006, the Company signed a contract with HAFB under which
the Company provides retail electric service and limited wheeling services to HAFB for a ten-year term which expired in January
2016 HAFB and the Company agreed to extend the retail pricing provisions of the existing agreement during negotiations for a
replacement contract. The contract was revised to include to allow for an extension of services under the existing agreement.

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.

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 document 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
settlement approved in the Company's 2012 Texas rate case, PUCT Docket No. 40094, established the Company's current retail
base rates in Texas, effective May 1, 2012. In addition, the settlement in the Company's 2009 New Mexico rate case, NMPRC
Case

, established rates in New Mexico that became effective in January 2010.

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 retirement and ARO. 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 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 May 11, 2015 and August 10, 2015, the Company filed a general rate case with the NMPRC, Case No. 15-00127-UT
(the “2015 New Mexico rate case”) and the PUCT, Docket No. 44941 (the “2015 Texas rate case”), respectively, to establish new
rates and to request recovery of new plant placed into service since 2009. Third parties have intervened in both rate cases and have
challenged whether certain of our costs are reasonable and necessary. The Company anticipates a resolution of both the 2015 New
Mexico rate case and the 2015 Texas rate case in the first or second quarter of 2016. If the NMPRC and PUCT do not increase the
Company’s rates adequately, the Company’s future operations, cash flow and financial condition could be materially adversely
affected. For a full discussion of these rate cases see Part II, Item 8, Financial Statements and Supplementary Data, Note C.

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

In 2013 and 2014, we received approval, both from the PUCT and the NMPRC, to construct four 88 MW simple-cycle
aeroderivative combustion turbines at our MPS, a new plant site. During 2013, we completed the construction of Rio Grande
Unit 9, an aeroderivative unit with a generating capacity of 87 MW, which reached commercial operation in May 2013. In 2015,
we completed construction of MPS Units 1 and 2 which began commercial operation in March 2015. We have risk related to
recovering all costs associated with the construction of Rio Grande Unit 9, MPS, and other new units and transmission assets.

In 2014, we issued $150 million in aggregate principal amount of 5.00% Senior Notes, due December 1, 2044. 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 being reviewed in the current Texas and New Mexico
rate cases. 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, such as MPS Units 3 and 4 are not completed on time, we may be required to purchase power or
operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be
subject to regulatory review by the PUCT and the NMPRC. We face financial risks to the extent that recovery is not allowed for
any replacement fuel costs resulting from delays in the completion of these new units or other new units.

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

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. 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,
subject 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 31% of our available net generating capacity and provided approximately 47% of
our energy requirements for the twelve months ended December 31, 2015. Palo Verde comprises approximately 27% 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 94.3% and 93.7% in the twelve months ended December 31, 2015
and 2014, respectively.

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; the ability to dispose of spent nuclear fuel; the ability to maintain adequate
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 New Mexico and Texas 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 repriced energy costs for Palo Verde Unit 3 in New Mexico. In the
event that recovery of fuel and purchased power expenses is denied in any reconciliation proceeding, the amounts recorded for
fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would
incur a loss to the extent of the disallowance.

In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust
for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. In
Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision
except in the month of December. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any

time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods
of significant increases in natural gas prices, the Company realizes a lag in the ability to reflect increases in fuel costs in its 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.

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 and Four Corners) 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.

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

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

Future Costs of Compliance with Environmental Laws and Regulations Could
Adversely Affect Our Operations and Financial Results

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

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

Quality Standards ("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

The Company emits GHG (including carbon dioxide) through the operation of its 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 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. Further, the U.S. signed on to 21st Conference of Parties Paris Agreement signed on December 12, 2015, and indications
are that the U.S. plans on relying heavily on the CPP to meet its early commitments. The potential impact of this Agreement and
GHG rules (if and when finalized) on the Company 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. FERC regulates the Company’s wholesale
operations, provision of transmission services and compliance with federally mandated reliability standards. Additional regulatory
authorities have jurisdiction over some of our operations and construction projects including the EPA, the DOE, the PUCT, the
NMPRC and various local regulatory districts (including the cities of El Paso and Las Cruces).

We must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective
orders. Should the Company 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 the Company or the Company’s 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.

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, 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.

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. The Company leases land in El Paso adjacent to the Newman Power Station under a
lease which expires in June 2033 with a renewal option of 25 years. The Company has several other leases for office and parking
facilities that expire within the next five years.

Item 3.

Legal Proceedings

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

See Item 1, Business - Environmental Matters and Regulation, 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.

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:

2014

First Quarter ............... $
Second Quarter ...........
Third Quarter..............
Fourth Quarter ............

2015

First Quarter ............... $
Second Quarter ...........
Third Quarter..............
Fourth Quarter ............

Sales Price

High

Low

Dividends

(End of period)

37.16
40.33
40.43
42.17

41.32
39.26
38.32
40.35

33.44
35.21
35.39
35.34

35.43
33.77
33.90
35.32

35.73
40.21
36.55
40.06

38.64
34.66
36.82
38.50

0.265
0.280
0.280
0.280

0.280
0.295
0.295
0.295

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,
2010 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.

EE
EEI Index
NYSE Composite

12/31/2010
100
100
100

12/31/2011
128
120
94

12/31/2012
121
123
106

12/31/2013
137
138
131

12/31/2014
161
178
136

12/31/2015
160
172
127

As of January 31, 2016, there were 2,437 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 $47.1 million in cash dividends
during the twelve months ended December 31, 2015. On January 28, 2016, the Board of Directors declared a quarterly cash
dividend of $0.295 per share payable on March 31, 2016 to shareholders of record on March 15, 2016. The Board of Directors
plans to review the Company's dividend policy annually in the second quarter of each year. Generally, we are targeting a
payout ratio of approximately 45% to 55%. 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 stockholders 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, 2015 under the 2011 Plan. The table below provides the amount of the fourth quarter issuer purchases of equity securities.

Period

October 1 to October 31, 2015
November 1 to November 30, 2015
December 1 to December 31, 2015

Total
Number
of Shares
Purchased (a)

Average Price
Paid per Share
(Including
Commissions)
—
—
37.42

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
393,816
393,816
393,816

— $
—
12,313

_____________________
(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."

Item 6. Selected Financial Data

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

Operating revenues ........................................................ $
Operating income...........................................................
Net income ..................................................................... $
Basic earnings per share:

2015

849,869

146,191

81,918

Net income.............................................................. $

2.03
Weighted average number of shares outstanding........... 40,274,986
Diluted earnings per share:

Years Ended December 31,

2014

917,525

151,163

91,428

2.27

2013

890,362

165,635

88,583

2.20

2012

852,881

168,658

90,846

2.27

2011

918,013

190,803

103,539

2.49

40,190,991

40,114,594

39,974,022

41,349,883

Net income.............................................................. $

2.03

2.27

2.20

2.26

2.48

Weighted average number of shares and dilutive

potential shares outstanding................................... 40,308,562

40,211,717

40,126,647

40,055,581

41,587,059

Dividends declared per share of common stock ............ $
Cash additions to utility property, plant and equipment $
281,458
Total assets..................................................................... $ 3,233,852
Long-term debt, net of current portion .......................... $ 1,134,284
Common stock equity .................................................... $ 1,016,538

1.165

1.105

277,078

1.045

237,411

0.97

202,387

0.66

178,041

$ 3,059,301

$ 2,786,288

$ 2,669,050

$ 2,396,851

$ 1,134,179

984,254

999,620

943,833

999,535

824,999

816,497

760,251

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

As you read this Management’s Discussion and Analysis, 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 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 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, 2015, we had recorded regulatory assets currently
subject to recovery in future rates of approximately $115.1 million and regulatory liabilities of approximately $24.3 million as
discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements.
Included in regulatory assets are regulatory tax assets of approximately $69.4 million primarily related to the regulatory treatment
of the equity portion of allowance for funds used during construction ("AFUDC") and state deferred income taxes.

In the event we determine that we can no longer apply the Financial Accounting Standards Board (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 base
rates in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation
proceeding or an audit, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed
to collect from our customers, and we could incur a loss to the extent of the disallowance.

The Company’s Texas fuel and purchased power costs through March 31, 2013 were reconciled in PUCT Docket No. 41852.
As of December 31, 2015, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are
approximately $413.8 million. The Company is required to file an application in 2016 for fuel reconciliation of the Company's
fuel expenses in its Texas jurisdiction for the period through March 31, 2016. The NMPRC approved the continuation of its use
of the Fuel and Purchase Power Cost Adjustment Clause without modification and the Company’s application requesting
reconciliation of fuel and purchased power costs through December 2012 in Case No. 13-00380-UT. New Mexico jurisdictional
costs subject to prudence review are for costs from January 2013 through December 31, 2015 and are approximately $194.4
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
in February following the prior calendar year. As of December 31, 2015, the RGEC fuel costs subject to review are 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 $72.8 million and represents approximately 89% of our total ARO balance
of $81.6 million at December 31, 2015. A 10% increase in the estimates of future Palo Verde decommissioning costs at current
price levels would have increased the ARO liability by $6.0 million at December 31, 2015.

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 and PUCT and the ANPP Participation Agreement.
Historically, we have been permitted to collect in rates in Texas and New Mexico the funding requirements for our nuclear
decommissioning trusts, except for a portion of Palo Verde Unit 3, which is deregulated in the New Mexico jurisdiction. While
we attempt to seek amounts in rates to meet decommissioning obligations, we are not able to conclude given the evidence available
to us now 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,
we could be required to increase our funding to the nuclear decommissioning trusts.

Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We
face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and
which were valued at $113.3 million as of December 31, 2015. A hypothetical 10% increase in interest rates would have reduced
the fair values of these funds by $1.2 million at December 31, 2015. Our decommissioning trust funds also include marketable
equity securities of approximately $117.5 million at December 31, 2015. A hypothetical 20% decrease in equity prices would have
reduced the fair values of these funds by $23.5 million at December 31, 2015. Declines in market prices could require that additional
amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements.

We do not anticipate expending monies held in the nuclear decommissioning trusts before 2044 or a later period when

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, 2015
totaled $147.2 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled
$11.0 million for the twelve months ended December 31, 2015.

Our pension and other post-retirement benefit liabilities and the related net periodic benefit costs are calculated on the basis
of a number of actuarial assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life
expectancy of retirees and health care cost inflation. For 2015, 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, 2015, the corresponding weighted-average discount rates
range from 3.99% to 4.59% depending upon the benefit plan.

Our overall expected long-term rate of return on assets for the pension trust fund is 7.0% effective January 1, 2016, 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, 2016. 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 7.0% annual rate
of increase in the per capita cost of covered health care benefits was assumed for 2016. 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 fiscal 2016, we expect to change the method used to estimate the service and interest components of net periodic benefit
cost for pension and other postretirement benefits. This change compared to the previous method will result in a decrease in the
service and interest 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. For fiscal
2016, we have 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 will account for this change as a change in accounting estimate and accordingly
will account for this prospectively. The change in estimate is anticipated to decrease the service and interest components of net
period benefit cost for pension and other post-retirement benefits by $2.9 million and $0.9 million, respectively, starting in 2016.

The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December

31, 2015 reported pension liability and our 2015 reported pension expense (in thousands):

Actuarial Assumption

Discount rate:

Increase 1%

Decrease 1%

Expected long-term rate of return on plan assets:

Increase 1%

Decrease 1%

Compensation rate:

Increase 1%

Decrease 1%

Increase (Decrease)

Impact on
Pension Liability

Impact on
Pension Expense

(40,115)
49,216

N/A

6,188
(5,640)

(3,779)
4,574

2,633
(2,633)

1,470
(1,316)

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December

31, 2015 other postretirement benefit obligations and our 2015 reported other postretirement benefit expense (in thousands):

Actuarial Assumption

Discount rate:

Increase 1%

Decrease 1%

Healthcare cost trend rate:

Increase 1%

Decrease 1%

Expected long-term rate of return on plan assets:

Increase 1%
Decrease 1%

Increase (Decrease)

Impact on
Other Post-
retirement
Benefit
Obligation

Impact on
Other Post-
retirement
Benefit
Expense

Impact on
Other Post-
retirement
Service and
Interest Cost

(11,754)
14,528

(1,750)
2,208

13,006
(11,718)

N/A
N/A

3,041
(2,396)

(398)
398

(423)
526

1,571
(1,211)

N/A
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 at December
31, 2015.

We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount
recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. The
unrecognized tax benefits that do not meet the recognition and measurement standards are $3.6 million at December 31, 2015.

The following is an overview of our results of operations for the years ended December 31, 2015, 2014 and 2013. Net income

and basic earnings per share for the years ended December 31, 2015, 2014 and 2013 are shown below:

Overview

Net income (in thousands) .................................................................................... $
Basic earnings per share........................................................................................

81,918
2.03

91,428
2.27

88,583
2.20

Years Ended December 31,

2015

2014

2013

Regulatory Lag

Our results of operations for the year ended December 31, 2015 compared to 2014 and 2013 have been negatively impacted
as a result of the completion and the placement in service of MPS Units 1 and 2 (including common plant, transmission lines and
substation) and the EOC in the first quarter of 2015, without a corresponding increase in revenues. This trend will continue until
new and higher rates become effective. The primary impact from these assets being placed in service includes a reduction in
amounts capitalized for allowance for funds used during construction ("AFUDC"), and increases in depreciation, operation and
maintenance expense, property taxes and interest cost.

The following table and accompanying explanations show the primary factors affecting the after-tax change in income

between the calendar years ended 2015 and 2014, 2014 and 2013, and 2013 and 2012 (in thousands):

Prior year December 31 net income ................................................. $
Change in (net of tax):

Increased (decreased) non-base revenue, net of energy expense .....
Increased (decreased) allowance for funds used during
construction ......................................................................................
Increased interest on long-term debt (net of capitalized interest) ....
Increased depreciation and amortization..........................................
(Increased) decreased administrative and general expense..............
Increased taxes other than income taxes ..........................................

Decreased (increased) operation and maintenance at fossil-fuel
generating plants ..............................................................................
Increased (decreased) retail non-fuel base revenues ........................
Increased (decrease) investment and interest income ......................

Decreased (increased) Palo Verde operations and maintenance
expense .............................................................................................
Other.................................................................................................
Current year December 31 net income............................................. $

2015

2014

2013

91,428

88,583

90,846

(5,370) (a)

3,779 (b)

2,345 (c)

(4,953) (d)
(4,516) (f)
(4,214) (h)
(1,653) (j)
(641)

(294)
9,290 (o)

3,084 (r)

6,157 (e)
(390)
(2,415) (i)
1,536 (k)
(3,252) (m)

(1,792) (n)
(3,533) (p)
5,309 (s)

895
(2,611) (g)
(696)
(2,011) (l)
(198)

751
(2,459) (q)
1,382 (s)

1,030
(1,273)
81,918

(1,635) (t)
(919)
91,428

964
(625)
88,583

______________________
Footnotes reflect pre-tax amounts
(a)

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.
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.
Non-base revenues, net of energy expenses increased due to an increase of $1.6 million in deregulated Palo Verde Unit
3 revenues and an increase of $0.5 million in off-system sales retained margins.
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.
AFUDC increased, primarily due to higher balances of construction work in progress subject to AFUDC, primarily
reflecting construction work in progress on MPS and the EOC.
Interest on long-term debt increased, primarily due to interest on $150 million of 5.00% Senior Notes issued in December
2014.
Interest on long-term debt increased, primarily due to interest on $150 million of 3.3% Senior Notes issued in December
2012, partially offset by the refunding and remarketing of two series of pollution control bonds at lower rates in August
2012.
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.
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.

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

(m)

(n)

(o)

(p)

(q)

(r)

(s)

(t)

Administrative and general expenses increased, primarily due to (i) increased employee incentive compensation and (ii)
increased pension and benefits costs due to changes in actuarial assumptions used to calculate expenses for the post-
retirement employee benefit plan. These increases were partially offset by decreased outside services in the current period
compared to the same period in 2014.
Administrative and general expense decreased, primarily due to decreased employee pensions and benefits reflecting
changes in actuarial assumptions used to calculate expenses for our employee pension and post-retirement benefit plans
and plan modifications.
Administrative and general expenses increased, primarily due to increased outside services related to software systems
support and improvements and increased consulting and legal services related to the analysis of our future involvement
at Four Corners.
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.
Operations and maintenance at our fossil fuel generating plants increased, primarily due to maintenance at the Four
Corners and Newman power stations in 2014 with a reduced level of maintenance expense in 2013, and increased payroll
expense.
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.
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.
Retail non-fuel base revenues decreased, primarily due to a decrease in sales to small commercial and industrial customers
and large commercial and industrial customers, reflecting the reduction in non-fuel base rates in Texas effective on May
1, 2012, and a 1.1% decrease in sales to public authorities.
Investment and interest income increased, primarily due to further diversification and re-balancing our Palo Verde
decommissioning trust fund equity portfolio.
Investment and interest income increased, primarily due to increased gains on the sales of equity investments in our Palo
Verde decommissioning trust funds.
Palo Verde operations and maintenance expense increased primarily due to increased payroll including incentive
compensation.

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.

Historical Results of Operations

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 2015, 2014 and 2013.

Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment
mechanisms. A significant portion of fuel costs are also recovered through base rates in New Mexico. We record deferred fuel
revenues for the difference between actual fuel costs and recoverable fuel revenues until such amounts are collected from or
refunded to customers. "Non-fuel base revenues" refers to our revenues from the sale of electricity excluding such fuel costs.

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

Years Ended December 31,

2015

2014

2013

Residential.............................................................................
Commercial and industrial, small .........................................
Commercial and industrial, large ..........................................
Sales to public authorities .....................................................
Total retail non-fuel base revenues ................................

44%
33
7
16
100%

42%
34
7
17
100%

43%
33
7
17
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 77% of our non-fuel base revenues. While this customer base is more
stable, it is also more sensitive to changes in weather conditions. The current rate structures in New Mexico and Texas reflect
higher base rates during the peak summer season of May through October and lower base rates during November through April
for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales
and revenues during the summer cooling season. 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,

2015

2014

2013

January 1 to March 31..........................................
April 1 to June 30.................................................
July 1 to September 30.........................................
October 1 to December 31 ...................................
Total..............................................................

18%
26
35
21
100%

19%
27
33
21
100%

20%
27
33
20
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 2015, 2014 and 2013.

Cooling degree days ......................................
Heating degree days ......................................

2,839
2,095

2,671
1,900

2,695
2,426

2015

2014

2013

10-year
Average

2,696
2,174

Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.4% and 1.3%
in 2015 and 2014, respectively. See the tables presented on pages 34 and 35 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 $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 an interruptible rate adjustment for a large
customer. Cooling degree days increased 6.3% in 2015, when compared to the same period last 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.

Retail non-fuel base revenues decreased by $5.4 million, or 1.0%, for the twelve months ended December 31, 2014 when
compared to the twelve months ended December 31, 2013. The decrease reflects a $3.0 million decrease from sales to public
authorities, primarily due to an increased use of an interruptible rate by a military installation customer, as well as other energy
savings from energy conservation and efficiency programs and use of solar distributed generation at military installations. The
decrease in retail non-fuel base revenues also resulted from a decline in sales to residential customers of $2.3 million and reflects
milder weather in 2014, primarily in the first quarter. The milder weather also suppressed sales to small commercial and industrial
customers, and to a lesser extent public authority customers. Heating degree days decreased 21.7% when compared to 2013, and
were 12.9% below the 10-year average. Cooling degree days were relatively consistent with both 2013 and the 10-year average.
KWh sales to residential customers decreased 1.4% while the average number of residential customers served increased 1.3%.
Retail non-fuel base revenues from sales to small commercial and industrial customers increased slightly, when compared to 2013,
due to a 2.0% increase in the average number of customers served partially offset by milder weather. KWh sales to, and retail
non-fuel base revenues from, large commercial and industrial customers decreased 2.8% and 2.5%, respectively, as several
customers terminated operations.

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

We over-recovered fuel costs by $13.3 million in the twelve months ended December 31, 2015. We under-recovered fuel
costs by $3.1 million and $10.8 million in the twelve months ended December 31, 2014 and 2013, respectively. In May 2014, we
implemented a 6.9% increase in our fixed fuel factor in Texas, which was based upon a formula that reflects increases in prices
for natural gas. On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed
fuel factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the
materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the
PUCT on May 20, 2015. In July 2014, the PUCT approved a settlement in the Texas fuel reconciliation proceeding designated as
PUCT Docket No. 41852 and financial implications of the settlement were recorded in the second quarter of 2014 increasing fuel
revenues by $2.2 million. In September 2014 and March 2015, $7.9 million and $5.8 million, respectively, were credited to
customers through the applicable fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear
fuel storage. At December 31, 2015, we had a net fuel over-recovery balance of $4.0 million, including an over-recovery balance
$0.1 million in Texas, $3.8 million in New Mexico and $0.1 million in the FERC jurisdiction.

Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily
made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations.
We have shared 100% of margins on non-arbitrage sales (as defined by the settlement) and 50% of margins on arbitrage sales with
our Texas customers since April 1, 2014. For the period from April 1, 2014 through June 30, 2015, our total share of margins
assignable to the Texas retail jurisdiction, on arbitrage and non-arbitrage off-system sales, may not exceed 10% of the total margins
assignable to the Texas retail jurisdiction on all off-system sales. Prior to April 1, 2014, we shared 90% of off-system sales margins
with our Texas customers, and we retained 10% of off-system sales margins. We are currently sharing 90% of off-system sales
margins with our New Mexico customers, and 25% of our off-system sales margins with our sales for resale customer under the
terms of their contract.

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, 2015, 2014 and 2013 (in thousands except for MWhs).

MWh sales .....................................
Sales revenue ................................. $
Fuel cost......................................... $
Total margins................................. $
Retained margins ........................... $

Years Ended December 31,

2015

2,500,947
64,816
52,406
12,410
1,362

2014

2,609,769
97,980
74,716
23,264
2,147

$
$
$
$

2013

2,472,622
82,806
68,241
14,565
1,549

$
$
$
$

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. Off-system sales revenues increased $15.2 million, or 18.3%, and the related retained
margins increased $0.6 million, or 38.6%, for the twelve months ended December 31, 2014 when compared to 2013 as a result of
higher average market prices for power and a 5.5% increase in MWh sales.

Comparisons of kWh sales and operating revenues are shown below:

Years Ended December 31:
kWh sales (in thousands):

Retail:

2015

2014

Amount

Percent

Increase (Decrease)

Residential............................................................
Commercial and industrial, small.........................
Commercial and industrial, large .........................
Sales to public authorities ....................................
Total retail sales..........................................

2,771,138
2,384,514
1,062,662
1,585,568
7,803,882

2,640,535
2,357,846
1,064,475
1,562,784
7,625,640

Wholesale:

Sales for resale .....................................................
Off-system sales ...................................................
Total wholesale sales ..................................
Total kWh sales ...................................

63,347
2,500,947
2,564,294
10,368,176

61,729
2,609,769
2,671,498
10,297,138

Operating revenues (in thousands):
Non-fuel base revenues:

Retail:

Residential .................................................. $
Commercial and industrial, small ...............
Commercial and industrial, large................
Sales to public authorities...........................
Total retail non-fuel base revenues......

Wholesale:

Sales for resale............................................
Total non-fuel base revenues...............

Fuel revenues:

Recovered from customers during the period ......
Under (over) collection of fuel (1) .......................
New Mexico fuel in base rates .............................
Total fuel revenues (2).........................

Off-system sales:

Fuel cost ...............................................................
Shared margins .....................................................
Retained margins..................................................
Total off-system sales..........................

246,265
187,436
40,411
91,244
565,356

2,455
567,811

127,765
(13,342)
72,129
186,552

52,406
11,048
1,362
64,816

234,371
185,388
39,239
92,066
551,064

2,277
553,341

161,052
3,110
71,614
235,776

74,716
21,117
2,147
97,980

Other (3) (4).................................................................

Total operating revenues...................... $

30,690
849,869

30,428
917,525

Average number of retail customers (5):

Residential ...................................................................
Commercial and industrial, small................................
Commercial and industrial, large.................................
Sales to public authorities............................................
Total.....................................................

356,969
40,250
49
5,250
402,518

352,277
39,600
49
5,088
397,014

130,603
26,668
(1,813)
22,784
178,242

1,618
(108,822)
(107,204)
71,038

11,894
2,048
1,172
(822)
14,292

178
14,470

(33,287)
(16,452)
515
(49,224)

(22,310)
(10,069)
(785)
(33,164)

262
(67,656)

4,692
650
—
162
5,504

4.9%
1.1
(0.2)
1.5
2.3

2.6
(4.2)
(4.0)
0.7

5.1%
1.1
3.0
(0.9)
2.6

7.8
2.6

(20.7)
-

0.7
(20.9)

(29.9)
(47.7)
(36.6)
(33.8)

0.9
(7.4)

1.3%
1.6

3.2
1.4

___________________________
(1)

Includes the portion of DOE refunds 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.
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.
Includes an Energy Efficiency Bonus of $1.3 million and $2.0 million in 2015 and 2014, respectively.
Represents revenues with no related kWh sales.
The number of retail customers presented is based on the number of service locations.

(2)
(3)
(4)
(5)

Years Ended December 31:
kWh sales (in thousands):

Retail:

2014

2013

Amount

Percent

Increase (Decrease)

Residential ...........................................................
Commercial and industrial, small........................
Commercial and industrial, large.........................
Sales to public authorities....................................
Total retail sales .........................................

2,640,535
2,357,846
1,064,475
1,562,784
7,625,640

2,679,262
2,349,148
1,095,379
1,622,607
7,746,396

Wholesale:

Sales for resale.....................................................
Off-system sales ..................................................
Total wholesale sales..................................
Total kWh sales...................................

61,729
2,609,769
2,671,498
10,297,138

61,232
2,472,622
2,533,854
10,280,250

Operating revenues (in thousands):
Non-fuel base revenues:

Retail:

Residential.................................................. $
Commercial and industrial, small ..............
Commercial and industrial, large...............
Sales to public authorities ..........................
Total retail non-fuel base revenues.....

Wholesale:

Sales for resale ...........................................
Total non-fuel base revenues ..............

Fuel revenues:

Recovered from customers during the period .....
Under collection of fuel (1) .................................
New Mexico fuel in base rates ............................
Total fuel revenues (2)........................

Off-system sales:

Fuel cost...............................................................
Shared margins ....................................................
Retained margins .................................................
Total off-system sales .........................

234,371
185,388
39,239
92,066
551,064

2,277
553,341

161,052
3,110
71,614
235,776

74,716
21,117
2,147
97,980

236,651
184,568
40,235
95,044
556,498

2,172
558,670

133,481
10,849
73,295
217,625

68,241
13,016
1,549
82,806

Other (3) (4)................................................................

Total operating revenues..................... $

30,428
917,525

31,261
890,362

Average number of retail customers (5):

Residential ..................................................................
Commercial and industrial, small ...............................
Commercial and industrial, large................................
Sales to public authorities...........................................
Total....................................................

352,277
39,600
49
5,088
397,014

347,891
38,836
50
4,997
391,774

(38,727)
8,698
(30,904)
(59,823)
(120,756)

497
137,147
137,644
16,888

(2,280)
820
(996)
(2,978)
(5,434)

105
(5,329)

27,571
(7,739)
(1,681)
18,151

6,475
8,101
598
15,174

(833)
27,163

4,386
764
(1)
91
5,240

(1.4)%
0.4
(2.8)
(3.7)
(1.6)

0.8
5.5
5.4
0.2

(1.0)%
0.4
(2.5)
(3.1)
(1.0)

4.8
(1.0)

20.7
(71.3)
(2.3)
8.3

9.5
62.2
38.6
18.3

(2.7)
3.1

1.3 %
2.0
(2.0)
1.8
1.3

_______________________
(1)
(2)
(3)
(4)
(5)

2014 includes a DOE refund related to spent fuel storage of $7.9 million offset in part by $2.2 million related to Palo Verde performance rewards, net.
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $15.0 million and $11.4 million in 2014 and 2013, respectively.
Includes an Energy Efficiency Bonus of $2.0 million and $0.5 million in 2014 and 2013, respectively.
Represents revenues with no related kWh sales.
The number of retail customers presented is based on the number of service locations.

Energy expenses

Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased
power. Palo Verde represents approximately 31% of our available net generating capacity and approximately 54% of our Company-
generated energy for the twelve months ended December 31, 2015. 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 $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.

Energy expenses increased $26.7 million, or 9.2%, for the twelve months ended December 31, 2014 compared to 2013,
primarily due to (i) increased natural gas costs of $32.7 million due to a 17.1% increase in the average costs of natural gas and a
2.4% increase in MWhs generated with natural gas, and (ii) increased total purchased power of $2.4 million due to a 17.5% increase
in the average price of total purchased power partially offset by a 10.2% decrease in MWhs purchased. Photovoltaic purchased
power costs per MWh decreased for the twelve months ended December 31, 2014, when compared to the same period in 2013
primarily due to the lower priced purchases from Macho Springs solar photovoltaic project which began commercial operation
in May 2014. The increase in energy expense was partially offset by a decrease in nuclear fuel expense related to an $8.5 million
settlement with the DOE for reimbursement of spent fuel storage and management costs recorded in 2014.

The table below details the sources and costs of energy for 2015, 2014 and 2013.

2014

MWh

Cost per
MWh

Cost

(in thousands)
196,833
$
12,883
41,289 (a)
251,005

3,774,209
596,252
5,106,668
9,477,129

19,575
45,229
64,804
315,809

227,979
1,162,511
1,390,490
10,867,619

52.15
21.61
9.76
27.39

85.86
39.80
47.35
29.94

Fuel Type

Cost

Natural Gas ................... $
Coal...............................
Nuclear..........................
Total.......................

(in thousands)
134,361
13,913
40,126 (a)
188,400

Purchase Power:

Photovoltaic...........
Other ......................
Total purchased power..

Total energy........... $

22,495
31,050
53,545
241,945

Fuel Type

Cost

Natural Gas ................... $
Coal...............................
Nuclear..........................
Total.......................

(in thousands)
164,139
13,680
48,949
226,768

Purchase Power:

Photovoltaic...........
Other ......................
Total purchased power..

Total energy........... $

13,863
48,500
62,363
289,131

2015

MWh

Cost per
MWh

3,790,659
657,744
5,136,686
9,585,089

277,241
1,113,705
1,390,946
10,976,035

35.45
21.15
9.06
20.32

81.14
27.88
38.50
22.63

2013

MWh

Cost per
MWh

3,686,823
635,717
4,966,233
9,288,773

120,926
1,427,004
1,547,930
10,836,703

44.52
21.52
9.86
24.41

114.64
33.99
40.29
26.68

_____________________
(a) Costs includes a DOE refund related to spent fuel storage of $6.4 million and $8.5 million recorded in the first quarter of
2015 and in the third quarter of 2014, respectively. Cost per MWh excludes this settlement.

Other operations expense

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 Palo Verde operations expense.

Other operations expense increased $1.7 million, or 0.7%, in 2014 compared to 2013 primarily due to (i) a $5.6 million
increase in other operations payroll costs including a $2.7 million increase in employee incentive compensation; (ii) a $1.5 million
increase in customer care expenses including an increase in uncollectible customer accounts; and (iii) a $1.5 million increase in
Palo Verde operations expense. These increases were partially offset by $5.5 million decrease in employee pensions and benefits
primarily due to changes in actuarial assumptions used to calculate expenses for our employee pension and post-retirement benefit
plans and plan modifications.

Maintenance expense

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 partially offset by maintenance at our MPS with no comparable
expenses during 2014. Maintenance expense increased $4.6 million, or 7.5%, in 2014 compared to 2013 due to an increase in
maintenance expense at Four Corners and Newman generating plants and increased payroll expense.

Depreciation and amortization expense

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. Depreciation and amortization expense increased $3.7 million, or 4.7%, in 2014 compared
to 2013, due to increases in depreciable plant balances primarily in our transmission and distribution plant and our local generating
plant, including Rio Grande Unit 9 which began commercial operation on May 13, 2013.

Taxes other than income taxes

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. Taxes other than income taxes increased $5.0 million, or 8.7%,
in 2014 compared to 2013, primarily due to higher property tax values and assessment rates and increases in revenue related taxes.
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.

Other income (deductions)

Other income (deductions) decreased $2.3 million, or 8.1%, in 2015 compared to 2014, primarily as a result of: (i) decreased
allowance for equity funds used during construction ("AEFUDC") resulting from lower average balances of construction work in
progress 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 find equity portfolio.

Other income (deductions) increased $13.9 million in 2014 compared to 2013, primarily as a result of: (i) increased investment
and interest income due to increased net realized gains on equity investments in our decommissioning trusts; (ii) increased AEFUDC
due to higher balances of construction work in progress including MPS and the EOC; and (iii) an increase in miscellaneous other
income due to a gain recognized on sale of assets in 2014 with a reduced level of activity in 2013.

Interest charges (credits)

Interest charges (credits) increased by $8.4 million, or 18.0%, in 2015 compared to 2014 primarily due to interest expense
on the $150 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in December 2014 and decreased allowance
for borrowed funds used during construction ("ABFUDC") as a result of lower balances of construction work in progress and a
reduction in the ABFUDC rate.

Interest charges (credits) decreased by $0.9 million, or 1.9%, in 2014 compared to 2013 primarily due to increased ABFUDC
as a result of higher balances of construction work in progress in 2014 partially offset by an increase in interest on short-term
borrowings for working capital purposes and interest expense on the $150 million of 5.00% Senior Notes due 2044 issued in
December 2014.

Income tax expense

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. These decreases were partially offset by a decrease in AEFUDC. Income
tax expense decreased by $2.6 million, or 5.9%, in 2014 compared to 2013 primarily due to (i) an increase in the AEFUDC, (ii)
an increase in capital gains on equity investments in our decommissioning trusts which are taxed at a lower rate, and (iii) an
increase in tax credits earned. These decreases were partially offset by an increase in state income taxes.

New accounting standards

In May 2014, the FASB issued new guidance (Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts
with Customers (Topic 606)) to provide a framework that replaces the existing revenue recognition guidance. ASU 2014-09 is the
result of a joint effort by the FASB and the International Accounting Standards Board intended to clarify the principles for
recognizing revenue and to develop a common revenue standard for U.S. Generally Accepted Accounting Principles ("GAAP")
and International Financial Reporting Standards. ASU 2014-09 provides that an entity should recognize the amount of revenue to
which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 was originally intended
to be effective for annual periods and interim periods within that reporting period beginning after December 15, 2016, for public
business entities. In August 2015, the FASB issued ASU 2015-14 to defer the effective date of ASU 2014-09 for all entities by
one year. Public business entities will apply the guidance in ASU 2014-09 to annual reporting periods beginning after December
15, 2017 and interim periods within that reporting period. Early adoption of ASU 2014-09 is permitted after December 15, 2016.
We have not selected a transition method and we are currently assessing the future impact of this ASU.

In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Topic 715) to simplify the presentation of
debt issuance costs. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance
sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and
measurement guidance for debt issuance costs are not affected by this ASU. ASU 2015-03 is effective for financial statements
issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. In August 2015, the FASB
issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30), to provide further clarification to ASU 2015-03 as it
relates to the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements. We do
not expect ASU 2015-03 and ASU 2015-15 to materially impact the Company's results of operations and cash flows.

In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820) to eliminate the requirement to categorize
investments in the fair value hierarchy if the fair value is measured at net asset value ("NAV") per share (or its equivalent) using
the practical expedient in the FASB’s fair value measurement guidance. Reporting entities must still provide sufficient information
to enable users to reconcile total investments in the fair value hierarchy and total investments measured at fair value in the financial
statements. Additionally, the scope of current disclosure requirements for investments eligible to be measured at NAV will be
limited to investments to which the practical expedient is applied. This ASU is effective in fiscal years beginning after December
15, 2015, and interim periods within those fiscal years. The ASU requires retrospective application. Early adoption is permitted.
This guidance requires a revision of the fair value disclosures but will not impact our 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. We are currently assessing the future impact of this ASU.

tax asset related to available-for-sale securities in combination with the entity's other deferred tax assets. The standard includes a
requirement that businesses must report changes in the fair value of their own liabilities in other comprehensive income instead
of earnings, and this is the only provision of the update for which the FASB is permitting early adoption. The remaining provisions
of this ASU become effective for public companies for fiscal years beginning after December 15, 2017, including interim periods
within those fiscal years. We are currently assessing the future impact of this ASU.

Inflation

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

and financial condition.

Liquidity and Capital Resources

We continue to maintain a strong balance of common stock equity in our capital structure which supports our bond ratings,
allowing us to obtain financing from the capital markets at a reasonable cost. At December 31, 2015, our capital structure, including
common stock, long-term debt, current maturities of long-term debt, and short-term borrowings under the RCF, consisted of 44.3%
common stock equity and 55.7% debt. At December 31, 2015, we had on hand $8.1 million in cash and cash equivalents. Based
on current projections, we believe that we will have adequate liquidity through the issuance of long-term debt, our current cash
balances, cash from operations, and available borrowings under the Revolving Credit Facility (“RCF”) to meet all of our anticipated
cash requirements for the next twelve months.

Our principal liquidity requirements in the near-term are expected to consist of capital expenditures to expand and support
electric service obligations, expenditures for nuclear fuel inventory, interest payments on our indebtedness, cash dividend payments,
operating expenses including fuel costs, maintenance costs and taxes.

Capital Requirements. During the twelve months ended December 31, 2015, our capital requirements primarily consisted
of expenditures for the construction and purchase of electric utility plant, cash dividend payments and purchases of nuclear fuel.
Projected utility construction expenditures are to add new generation, expand and update our transmission and distribution systems,
and make capital improvements and replacements at Palo Verde and other generating facilities. MPS Units 1 and 2, the first two
(of four) natural gas-fired 88 MW simple-cycle aeroderivative combustion turbines, were completed and placed in service during
the first quarter of 2015. The total cost for these two units and the related common facilities and transmission systems, including
AFUDC, was approximately $228.7 million. Units 3 and 4 are projected to be completed in 2016. In 2015 we incurred approximately
$120.4 million in cost for MPS, including AFUDC. Estimated cash construction expenditures for MPS in 2016 are approximately
$39 million and estimated construction expenditures for all capital projects for 2016 are approximately $231 million. See Part I,
Item 1, "Business - Construction Program." Cash capital expenditures for new electric plant were $281.5 million in the twelve
months ended December 31, 2015 and $277.1 million in the twelve months ended December 31, 2014. Capital requirements for
purchases of nuclear fuel were $42.0 million for the twelve months ended December 31, 2015 and $37.9 million for the twelve
months ended December 31, 2014.

On December 30, 2015, we paid a quarterly cash dividend of $0.295 per share or $11.9 million to shareholders of record on
December 15, 2015. We paid a total of $47.1 million in cash dividends during the twelve months ended December 31, 2015. On
January 28, 2016, our Board of Directors declared a quarterly cash dividend of $0.295 per share payable on March 31, 2016 to
shareholders of record at the close of business on March 15, 2016 which will require cash of $11.9 million. We expect to continue
paying quarterly dividends during 2016 and we expect to review the dividend policy in the second quarter of 2016. At the current
payout rate, we would expect to pay total cash dividends of approximately $47.6 million during 2016. In addition, while we do
not currently anticipate repurchasing shares of our common stock in 2016, we may repurchase shares of our common stock in the
future. Under our repurchase program, purchases can be made at open market prices or in private transactions, and repurchased
shares are available for issuance under employee benefit and stock incentive plans, or may be retired. Beginning in 2015 shares
of our common stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and
held in treasury stock. During 2015, 108,085 shares were awarded out of treasury stock. No shares of our common stock were
repurchased in 2015, 2014 or 2013. As of December 31, 2015, 393,816 shares remain eligible for repurchase under the repurchase
program.

We will continue to maintain a prudent level of liquidity and monitor market conditions for debt and equity securities. We
primarily utilize the distribution of dividends to maintain a balanced capital structure and supplement this effort with share
repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing
to make investments in new electric plant and other assets in order to reliably serve our customers. In light of these factors, we
expect it will be a number of years before we achieve a dividend payout equivalent to industry average.

Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced
by the timing of revenues and expenses recognized for income tax purposes. Due to net operating loss carryforwards resulting
from accelerated depreciation deductions, income tax payments are expected to be minimal in 2016.

We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans, and
decommissioning trust funds. We contributed $10.9 million to our retirement plans during both the twelve months ended
December 31, 2015 and 2014. We contributed $0.5 million to our other post-retirement benefit plans during the twelve months
ended December 31, 2015 and we did not make any contributions to our other post-retirement benefit plans during the twelve
months ended December 31, 2014. We contributed $4.5 million to our decommissioning trust funds in both 2015 and 2014. We
are in compliance with the funding requirements of the federal government for our benefit plans. In addition, with respect to our
nuclear plant decommissioning trust, we are in compliance with the funding requirements of the federal law and the ANPP
Participation Agreement. We will continue to review our funding for these plans in order to meet our future obligations.

In 2010, the Company and 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 million aggregate principal amount of senior notes. In August 2015, $15.0 million of these senior notes matured and were
paid with borrowings from the RCF.

Capital Resources. Cash provided by operations, $246.7 million in 2015 and $243.3 million in 2014, is a significant source
for funding capital requirements. Cash from operations has been impacted by the timing of the recovery of fuel costs through fuel
recovery mechanisms in Texas and New Mexico and our sales for resale customer. We recover actual fuel costs from customers
through fuel adjustment mechanisms in Texas, New Mexico, and from our sales for resale customer. We record deferred fuel
revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas,
fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor at least four months after our last
revision except in the month of December based upon our approved formula which allows us to adjust fuel rates to reflect changes
in costs of natural gas. We are required to request to refund fuel costs in any month when the over-recovery balance exceeds a
threshold material amount and we expect fuel costs to continue to be materially over-recovered. We are permitted to seek to
surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount that we expect fuel cost recovery
to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of
the previous twelve months' fuel costs. On May 1, 2015, we reduced our fixed fuel factor charged to our Texas retail customers
by approximately 24% to reflect reduced fuel expense.

2015 earnings were adversely impacted by the regulatory lag resulting from placing into service during the first quarter, the
first two generating units at MPS together with the related transmission lines and substation as well as the EOC. We incurred
approximately $269.3 million in construction costs for these facilities. With the introduction of these facilities into service, we
have begun to incur increased expenses related to depreciation, operations and maintenance, property taxes, and interest cost.
Furthermore, we have ceased recognizing AFUDC on these facilities. We have filed for an increase in base rates for our New
Mexico and Texas service territory on May 11, 2015 and August 10, 2015, respectively; and we expect new rates to become
effective in the second quarter of 2016 in both jurisdictions. The Company also expects 2016 earnings to be adversely impacted
by the regulatory lag resulting from the commercialization of MPS Units 3 and 4 which are expected to be placed in service during
the second and fourth quarters of 2016, respectively. Base rate increases to seek recovery of these costs are expected to be filed
in the first quarter of 2017 for both jurisdictions.

During the twelve months ended December 31, 2015, net fuel recoveries resulted in increased cash from operations when
compared to 2014. During the twelve months ended December 31, 2015 the Company had a fuel over-recovery of $13.3 million
compared to an under-recovery of fuel costs of $3.1 million during the twelve months ended December 31, 2014. At December
31, 2015, we had a net fuel over-recovery balance of $4.0 million, including an over-recovery balance of $0.1 million in Texas,
$3.8 million in New Mexico and $0.1 million in the FERC jurisdiction.

In December 2014, we issued $150 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044. The
gross proceeds from the issuance of the senior notes were $149.5 million, net of a $0.5 million discount before commissions and
expenses and the effective interest rate was 5.10%. The net proceeds from the sale of these senior notes were used to fund
construction expenditures and to repay the outstanding balance of our RCF used for working capital and general corporate purposes.

We maintain the RCF for working capital and general corporate purposes and the financing of nuclear fuel through the RGRT.
The RGRT is the trust through which we finance our portion of nuclear fuel for Palo Verde and is consolidated in our financial
statements. On January 14, 2014, we amended and extended our $300 million RCF, which includes an option to expand the size
to $400 million, upon the satisfaction of certain conditions including obtaining commitments from lenders or third party financial
institutions. The amended facility extends the maturity from September 2016 to January 2019. In addition, we may extend the
January 2019 maturity, subject to lenders' approval, by two additional one year periods. In August 2015, $15 million Series A

3.67% Senior Notes of the RGRT matured and were paid utilizing the RCF. The total amount borrowed for nuclear fuel by the
RGRT was $128.7 million at December 31, 2015, of which $33.7 million had been borrowed under the RCF and $95 million was
borrowed through the issuance of senior notes. Borrowings by RGRT for nuclear fuel were $124.5 million at December 31, 2014,
of which $14.5 million had been borrowed under the RCF and $110 million was borrowed through senior notes. Interest costs on
borrowings to finance nuclear fuel are accumulated by the RGRT and charged to us as fuel is consumed and recovered from
customers through fuel recovery charges. The outstanding balance for working capital or general corporate purposes was $108
million at December 31, 2015. No borrowings were outstanding December 31, 2014 for working capital and general corporate
purposes. Total aggregate borrowings under the RCF at December 31, 2015 were $141.7 million with an additional $157.8 million
available to borrow.

We believe we have adequate liquidity through our current cash balances, cash from operations, available borrowings under
the RCF and potential access to capital markets to meet all of our anticipated cash requirements for the next twelve months. We
received approval from the NMPRC on October 7, 2015 and from the FERC on October 19, 2015, to issue up to $310 million in
new long-term debt and to guarantee the issuance of up to $65 million of new debt by the RGRT to finance future purchases of
nuclear fuel and to refinance existing nuclear fuel debt obligations. We also received 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. The authorizations
to issue up to $310 million of long-term debt and to guarantee up to $65 million of new long-term debt by RGRT provides us with
the flexibility to access the debt capital markets if conditions are favorable.

Contractual Obligations. Our contractual obligations as of December 31, 2015 are as follows (in thousands):

Payments due by period

Total

2016

2017 and
2018

2019 and
2020

2021 and
Beyond

Long-Term Debt (including interest):

Senior notes (1)........................................... $ 1,823,275
Pollution control bonds (2) .........................
444,836

RGRT Senior notes (3) ...............................

110,810

Financing Obligations (including interest):

Revolving credit facility (4)........................

143,683

Purchase Obligations:

Power contracts...........................................

891

Fuel contracts:

Coal (5)................................................

Gas (5) .................................................

Nuclear fuel (6)....................................

Retirement Plans and Other Post-retirement
benefits (7) .........................................................

Nuclear decommissioning trust funds (8) ..........

2,855

348,962

106,332

7,892

2,000

Operating leases (9) ...........................................

10,358
Total ........................................... $ 3,001,894

_____________________
(1)

2,855

52,959

25,590

7,892

2,000

900

47,700

95,400

$ 1,584,775

10,583

4,503

53,634

56,771

19,918

49,536

360,701

—

62,009

19,875

170,161

32,555

—

63,833

28,312

—

299,556

299,136

247,827

$ 2,155,375

1,186

1,089

7,183

We have four outstanding issuances of Senior Notes. In May 2005, we issued $400 million aggregate principal amount
of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150 million aggregate principal amount of 7.5% Senior
Notes due March 15, 2038. In December 2012, we issued $150 million aggregate principal amount of 3.3% Senior Notes
due December 15, 2022. In December 2014, we issued $150 million aggregate principal amount of 5.0% Senior Notes
due December 1, 2044.
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.
In 2010, the Company and RGRT entered into a note purchase agreement for $110 million aggregate principal amount
of senior notes consisting of: (a) $15 million aggregate principal amount of 3.67% RGRT Senior Notes, Series A, which
matured and were repaid on August 15, 2015; (b) $50 million aggregate principal amount of 4.47% RGRT Senior Notes,
Series B, due August 15, 2017; and (c) $45 million aggregate principal amount of 5.04% RGRT Senior Notes, Series C,
due August 15, 2020.
This reflects obligations outstanding under the $300 million RCF. At December 31, 2015, $108.0 million was borrowed
for working capital and general corporate purposes and $33.7 million was borrowed by RGRT for nuclear fuel. This
balance includes interest based on actual interest rates at the end of 2015 and assumes this amount will be outstanding
for the entire year of 2016.
Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2015. Gas
obligation includes a gas storage contract and a gas transportation contract.
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 2015.
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 2016. We have no minimum cash
contractual funding requirement related to our retirement income plan or other post-retirement benefits for 2016. However,
we are subject to minimum funding requirements of ERISA. We also may decide to fund at higher levels and expect to
contribute $7.9 million to our retirement plans in 2016, as disclosed in Part II, Item 8, Notes to Financial Statements,
Note M. Minimum funding requirements for 2017 and beyond are not included due to the uncertainty of interest rates
and the related return on assets.
This obligation is based on our expected contributions in 2016. We anticipate having no minimum funding obligation in
either Texas or New Mexico jurisdiction once new rates become effective given that funding was not requested in either
PUCT Docket No. 44941or NMPRC Case No. 15-00127-UT. The current funding levels of $0.3 million per month in

(2)

(3)

(4)

(5)

(6)

(7)

(8)

(9)

Texas and $0.1 million per month in New Mexico are anticipated to continue until the new rates go into effect. However,
funding requirements may change in the future and could require an increase in funding levels in both jurisdictions.
We lease land in El Paso adjacent to the Newman Power Station under a lease that expires in June 2033 with a renewal
option of 25 years. We also have several other leases for office, parking facilities and equipment that expire within the
next five years.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our
financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or
capital resources.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

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

We are exposed to market risk due to changes in interest rates, equity prices and commodity prices. Substantially all financial

instruments and positions we hold are for purposes other than trading and are described below.

Interest Rate Risk

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

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

Equity Price Risk

Our decommissioning trust funds include marketable equity securities of approximately $117.5 million and $123.4 million
at December 31, 2015 and 2014, respectively. A hypothetical 20% decrease in equity prices would have reduced the fair values
of these funds by $23.5 million and $24.7 million based on their fair values at December 31, 2015 and 2014, 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, uranium concentrates and coal 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, 2016, 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.

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, 2015. 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, 2015, 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 47 of this report.

Item 8.

Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm ...................................................................................................

Balance Sheets as of December 31, 2015 and 2014................................................................................................................

Statements of Operations for the years ended December 31, 2015, 2014 and 2013...............................................................

Statements of Comprehensive Operations for the years ended December 31, 2015, 2014 and 2013 ...................................

Statements of Changes in Common Stock Equity for the years ended December 31, 2015, 2014 and 2013........................

Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013 .............................................................

Notes to Financial Statements.................................................................................................................................................

Page

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
El Paso Electric Company:

We have audited the accompanying balance sheets of El Paso Electric Company (the Company) as of December 31, 2015 and
2014, 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, 2015. We also have audited El Paso Electric Company’s internal
control over financial reporting as of December 31, 2015, 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, 2015 and 2014, and the results of its operations and its cash flows for each of the years in
the three-year period ended December 31, 2015, 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, 2015, 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

Kansas City, Missouri
February 29, 2016

EL PASO ELECTRIC COMPANY
BALANCE SHEETS

Utility plant:

ASSETS
(In thousands)

December 31,

2015

2014

Electric plant in service ........................................................................................................... $ 3,616,301
(1,329,843)
Less accumulated depreciation and amortization....................................................................
2,286,458
Net plant in service...........................................................................................................
293,796
Construction work in progress.................................................................................................

$ 3,229,255
(1,266,672)
1,962,583
414,284

Nuclear fuel; includes fuel in process of $51,854 and $46,996, respectively .........................
Less accumulated amortization ...............................................................................................
Net nuclear fuel ................................................................................................................
Net utility plant .......................................................................................................

190,282
(75,031)
115,251

185,185
(73,701)
111,484

2,695,505

2,488,351

Current assets:

Cash and cash equivalents .......................................................................................................
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,046
and $2,253, respectively ..........................................................................................................
Accumulated deferred income taxes .......................................................................................
Inventories, at cost...................................................................................................................
Under-collection of fuel revenues ...........................................................................................
Prepayments and other ............................................................................................................
Total current assets .................................................................................................

8,149

40,504

66,326

21,621

48,697

—

9,872

71,165

13,957

45,889

10,253

12,213

154,665

193,981

Deferred charges and other assets:

Decommissioning trust funds ..................................................................................................
Regulatory assets .....................................................................................................................
Other ........................................................................................................................................
Total deferred charges and other assets ..................................................................

383,682
Total assets...................................................................................................... $ 3,233,852

239,035

115,127

29,520

234,286

112,086

30,597

376,969

$ 3,059,301

See accompanying notes to financial statements.

EL PASO ELECTRIC COMPANY
BALANCE SHEETS (Continued)

Capitalization:

CAPITALIZATION AND LIABILITIES
(In thousands except for share data)

Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,709,819 and
65,725,246 shares issued, and 118,834 and 124,297 restricted shares, respectively............... $
Capital in excess of stated value..............................................................................................
Retained earnings ....................................................................................................................
Accumulated other comprehensive loss, net of tax .................................................................

Treasury stock, 25,384,834 and 25,492,919 shares, respectively, at cost

Common stock equity.......................................................................................................
Long-term debt, net of current portion ....................................................................................
Total capitalization..................................................................................................

Current liabilities:

Current maturities of long-term debt.......................................................................................
Short-term borrowings under the revolving credit facility......................................................
Accounts payable, principally trade ........................................................................................
Taxes accrued ..........................................................................................................................
Interest accrued........................................................................................................................
Over-collection of fuel revenues .............................................................................................
Other ........................................................................................................................................
Total current liabilities............................................................................................

Deferred credits and other liabilities:

Accumulated deferred income taxes .......................................................................................
Accrued pension liability.........................................................................................................
Accrued post-retirement benefit liability.................................................................................
Asset retirement obligation......................................................................................................
Regulatory liabilities ...............................................................................................................
Other ........................................................................................................................................
Total deferred credits and other liabilities ..............................................................

Commitments and contingencies

December 31,

2015

2014

65,829
320,073
1,067,396
(13,914)
1,439,384
(422,846)
1,016,538
1,134,284
2,150,822

65,850
318,515
1,032,537
(8,001)
1,408,901
(424,647)
984,254
1,134,179
2,118,433

—
141,738
59,978
30,351
12,649
4,023
28,325
277,064

516,858
90,527
54,553
81,621
24,303
38,104
805,966

15,000
14,532
78,862
28,210
12,758
932
24,715
175,009

474,154
94,272
59,342
74,577
26,099
37,415
765,859

Total capitalization and liabilities................................................................ $ 3,233,852

$ 3,059,301

See accompanying notes to financial statements.

EL PASO ELECTRIC COMPANY
STATEMENTS OF OPERATIONS
(In thousands except for share data)

Operating revenues ............................................................................................. $
Energy expenses:

Fuel ................................................................................................................

Purchased and interchanged power................................................................

Operating revenues net of energy expenses ......................................................
Other operating expenses:

Years Ended December 31,

2015

2014

2013

849,869

917,525

890,362

188,400

53,545

241,945

607,924

251,005

64,804

315,809

601,716

226,768

62,363

289,131

601,231

Other operations.............................................................................................

242,950

238,832

237,155

Maintenance...................................................................................................

Depreciation and amortization.......................................................................

Taxes other than income taxes.......................................................................

Operating income ................................................................................................
Other income (deductions):

Allowance for equity funds used during construction ...................................

Investment and interest income, net...............................................................

Miscellaneous non-operating income ............................................................

Miscellaneous non-operating deductions.......................................................

Interest charges (credits):

Interest on long-term debt and revolving credit facility ................................

Other interest..................................................................................................

Capitalized interest.........................................................................................

Allowance for borrowed funds used during construction..............................

Income before income taxes ...............................................................................
Income tax expense .............................................................................................

Net income ................................................................................... $

Basic earnings per share..................................................................................... $

Diluted earnings per share ................................................................................. $

Dividends declared per share of common stock ............................................... $
Weighted average number of shares outstanding ............................................
Weighted average number of shares and dilutive potential shares
outstanding ..........................................................................................................

See accompanying notes to financial statements.

65,223

89,824

63,736

461,733
146,191

10,639

17,508

2,062
(4,328)
25,881

65,851

1,313
(4,968)
(6,937)
55,259

116,813

34,895

81,918

2.03

1.165

65,629

83,342

62,750

450,553
151,163

14,662

13,633

4,075
(4,199)
28,171

59,028

1,250
(5,092)
(8,368)
46,818

132,516

41,088

91,428

2.27

1.105

61,068

79,626

57,747

435,596
165,635

10,008

7,033

909
(3,635)
14,315

58,635

431
(5,299)
(6,055)
47,712

132,238

43,655

88,583

2.20

1.045

40,274,986

40,190,991

40,114,594

40,308,562

40,211,717

40,126,647

EL PASO ELECTRIC COMPANY
STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)

Net income ................................................................................................................ $
Other comprehensive income (loss):

Unrecognized pension and post-retirement benefit costs:

Years Ended December 31,

2015

2014

2013

81,918

91,428

88,583

Net gain (loss) arising during period ...........................................................

Prior service benefit.....................................................................................

5,429

824

(54,328)
34,200

82,964

(5,560)
10,472

17,699
(553)

(6,574)
8,622

(2,906)
(11,114)

(7,659)
6,182

10,827
(7,350)

467
(5,252)

438
(17,690)

411

105,530

(3,286)
2,828
(203)
(661)
(5,913)
76,005

8,051
(760)
(214)
7,077
(10,613)
80,815

(33,566)
(3,100)
(168)
(36,834)
68,696

157,279

Reclassification adjustments included in net income for amortization of:

Prior service benefit ...........................................................................

Net loss...............................................................................................

Net unrealized gains/losses on marketable securities:

Net holding (losses) gains arising during period.........................................

Reclassification adjustments for net gains included in net income.............

Net losses on cash flow hedges:

Reclassification adjustment for interest expense included in net income ...

Total other comprehensive income (loss) before income taxes..........................

Income tax benefit (expense) related to items of other comprehensive income
(loss):

Unrecognized pension and post-retirement benefit costs............................

Net unrealized losses (gains) on marketable securities ...............................

Losses on cash flow hedges.........................................................................

Total income tax benefit (expense).....................................................................
Other comprehensive income (loss), net of tax......................................................
Comprehensive income............................................................................................ $

See accompanying notes to financial statements.

EL PASO ELECTRIC COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(In thousands except for share data)

Common Stock

Shares
65,604,997

Amount

65,605

Capital in
Excess of
Stated Value
310,994
$

Accumulated
Other
Comprehensive
Income (Loss),
Net of Tax

Retained
Earnings

939,131

(66,084)

Treasury Stock

Shares
25,492,919

Amount

(424,647) $

Common
Stock Equity
824,999

Balances at December 31, 2012...........................................

Restricted common stock grants and deferred

compensation .............................................................
Performance share awards vested ..................................
Stock awards withheld for taxes ....................................
Forfeited restricted common stock.................................
Deferred taxes on stock incentive plan ..........................
Stock options exercised..................................................
Compensation paid in shares .........................................
Net income .....................................................................
Other comprehensive income (loss)...............................
Dividends declared.........................................................
Balances at December 31, 2013...........................................

Restricted common stock grants and deferred

compensation .............................................................
Stock awards withheld for taxes ....................................
Forfeited restricted common stock.................................
Deferred taxes on stock incentive plan ..........................
Compensation paid in shares .........................................
Net income .....................................................................
Other comprehensive income (loss)...............................
Dividends declared

96,279
64,275
(23,808)
(1,549)

15,000
4,431

96
64
(23)
(1)

15
4

2,702
785
(788)

427
177
146

65,759,625

65,760

314,443

103,672
(4,696)
(19,162)

10,104

104
(5)
(19)

4,175
(183)

(302)
382

2,798
849
(811)
(1)
427
192
150
88,583
68,696
(42,049)
943,833

4,279
(188)
(19)
(302)
392
91,428
(10,613)
(44,556)
984,254

88,583

(42,049)
985,665

91,428

(44,556)
1,032,537

68,696

2,612

25,492,919

(424,647)

(10,613)

(8,001)

25,492,919

(424,647)

Balances at December 31, 2014...........................................

65,849,543

65,850

318,515

Restricted common stock grants and deferred

See accompanying notes to financial statements.

6,356
(15,031)
(12,215)

6
(15)
(12)

2,266
(556)

(475)
323

(93,455)

871

(15,501)

65,828,653

65,829

320,073

81,918

(47,059)
$ 1,067,396

(5,913)

(13,914)

25,384,834

(14)

1,557

3,829
(571)
(26)
(475)
581
81,918
(5,913)
(47,059)
(422,846) $ 1,016,538

258

EL PASO ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(In thousands)

Cash Flows From Operating Activities:

Net income ......................................................................................................................... $
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service .........................................
Amortization of nuclear fuel ......................................................................................
Deferred income taxes, net ........................................................................................
Allowance for equity funds used during construction ...............................................
Other amortization and accretion ...............................................................................
Gain on sale of property, plant and equipment ..........................................................
Net gains on sale of decommissioning trust funds .....................................................
Other operating activities ..........................................................................................

Change in:

Accounts receivable ...................................................................................................
Inventories .................................................................................................................
Net over-collection (under-collection) of fuel revenues ............................................
Prepayments and other ..............................................................................................
Accounts payable ......................................................................................................
Taxes accrued ............................................................................................................
Other current liabilities ..............................................................................................
Deferred charges and credits .....................................................................................
Net cash provided by operating activities ...................................................

Cash Flows From Investing Activities:

Cash additions to utility property, plant and equipment .....................................................
Cash additions to nuclear fuel ............................................................................................
Capitalized interest and AFUDC:

Utility property, plant and equipment ........................................................................
Nuclear fuel ...............................................................................................................
Allowance for equity funds used during construction ...............................................

Decommissioning trust funds:

Purchases, including funding of $4.5 million ............................................................
Sales and maturities ...................................................................................................
Proceeds from sale of property, plant and equipment ........................................................
Other investing activities ...................................................................................................
Net cash used for investing activities ..........................................................

Cash Flows From Financing Activities:

Dividends paid ...................................................................................................................
Borrowings under the revolving credit facility:

Proceeds ....................................................................................................................
Payments ...................................................................................................................
Payment on maturing RGRT senior notes ..........................................................................
Proceeds from issuance of senior notes .............................................................................
Other financing activities ...................................................................................................
Net cash provided by (used for) financing activities ..................................
Net increase (decrease) in cash and cash equivalents ............................................................
Cash and cash equivalents at beginning of period .................................................................

Years Ended December 31,

2015

2014

2013

81,918

91,428

88,583

89,824
43,099
30,846
(10,639)

17,707
(658)
(11,114)
517

4,839
(2,859)
13,344
(3,984)
(11,235)
4,512
3,719
(3,165)
246,671

83,342
43,864
39,129
(14,662)

18,380
(2,092)
(7,350)
(93)

(5,815)
(786)
(3,121)
(2,750)
9,684
(2,209)
1,198
(4,807)
243,340

79,626
42,537
44,678
(10,008)

16,556
(112)
(553)
(260)

(2,450)
(3,673)
(10,843)
(4,295)
8,180
(627)
958
(822)
247,475

(281,458)
(41,966)

(277,078)
(37,877)

(237,411)
(30,535)

(17,576)
(4,968)
10,639

(110,223)
102,567
721
(470)
(342,734)

(23,030)
(5,092)
14,662

(117,675)
108,311
2,395
4,192
(331,192)

(16,063)
(5,299)
10,008

(65,491)
56,148
112
5,767
(282,764)

(47,059)

(44,556)

(42,049)

344,398
(217,192)

(15,000)
—
(1,439)
63,708

(32,355)

40,504

231,399
(231,219)

—
149,468
(2,328)
102,764

14,912

25,592

44,883
(52,686)

—
—
(324)
(50,176)

(85,465)

111,057

25,592

Cash and cash equivalents at end of period ........................................................................... $

8,149

40,504

See accompanying notes to financial statements.

INDEX TO NOTES TO FINANCIAL STATEMENTS

Note A. Summary of Significant Accounting Policies ...........................................................................................................

Note B. New Accounting Standards .......................................................................................................................................

Note C. Regulation .................................................................................................................................................................

Note D. Regulatory Assets and Liabilities..............................................................................................................................

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

Note F. Accounting for Asset Retirement Obligations ...........................................................................................................

Note G. Common Stock..........................................................................................................................................................

Note H. Accumulated Other Comprehensive Income (Loss) .................................................................................................

Note I. Long-Term Debt and Financing Obligations..............................................................................................................

Note J. Income Taxes..............................................................................................................................................................

Note K. Commitments, Contingencies and Uncertainties ......................................................................................................

Note L. Litigation ...................................................................................................................................................................

Note M. Employee Benefits ...................................................................................................................................................

Note N. Franchises and Significant Customers ......................................................................................................................

Note O. Financial Instruments and Investments.....................................................................................................................

Page
55

Note P. Supplemental Statements of Cash Flow Disclosures .................................................................................................

103

Note Q. Selected Quarterly Financial Data (Unaudited) ........................................................................................................

104

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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 statement 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 2015, 2014 and 2013 was 2.64%, 2.60%, and 2.61%, 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.

The Company currently reports gains and losses on dispositions of vehicles in earnings when realized. Beginning in 2016,
the Company will adopt composite depreciation rates for vehicles. As such, the Company will charge the cost together with the
cost of removal, less 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 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

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

charged to all new eligible construction and capital improvement projects. AFUDC is compounded on a semi-annual basis. The
average AFUDC rates used in 2015, 2014 and 2013 were 7.18%, 8.15% and 8.10%, 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 sheets, 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 fair value of marketable securities below original cost basis are determined to be other than
temporary, then the declines are reported as losses in the statement 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 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 Public Utility Commission of Texas ("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 New Mexico
Public Regulation Commission ("NMPRC"). The Company's FERC sales for resale customers are billed under formula base rates
and fuel factors and a fuel adjustment clause which is adjusted monthly. The Company’s recovery of energy expenses is subject
to periodic reconciliations of actual energy expenses incurred to actual fuel revenues collected. The difference between energy
expenses incurred and fuel revenues charged to customers is reflected as over/under-collection of fuel revenues in the balance
sheets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

Revenues. Revenues related to the sale of electricity are generally recorded when service is provided or electricity is delivered
to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic
basis throughout the month. Unbilled revenues are recorded for estimated amounts of energy delivered in the period following
the customers billing cycle to the end of the month. Unbilled revenues are estimated based on monthly generation volumes and
by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included
accrued unbilled revenues of $21.7 million and $21.2 million at December 31, 2015 and 2014, 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 2015, 2014 and
2013 are as follows (in thousands):

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Balance at beginning of year ....................................................................... $
Additions:

Charged to costs and expense...............................................................
Recovery of previous write-offs...........................................................
Uncollectible receivables written off...........................................................
Balance at end of year ................................................................................. $

2015

2014

2013

2,253

2,261

2,906

2,057
1,613
3,877
2,046

2,755
1,516
4,279
2,253

2,098
1,929
4,672
2,261

Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting
for income taxes. Deferred income taxes are recognized for the estimated future tax consequences of "temporary differences" by
applying enacted statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial
statement carrying amounts and the tax basis of existing assets and liabilities. Certain temporary differences are accorded flow-
through treatment by the Company's regulators and impact the Company's effective tax rate. The FASB guidance requires that
rate-regulated companies record deferred income taxes for temporary differences accorded flow-through treatment at the direction
of the regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected
in future rates. Because the Company's regulators have consistently permitted the recovery of tax effects previously flowed-
through earnings, the Company has recorded regulatory liabilities and assets offsetting such deferred tax assets and liabilities.
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.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

New Accounting Standards

In May 2014, the FASB issued new guidance (Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts
with Customers (Topic 606)) to provide a framework that replaces the existing revenue recognition guidance. ASU 2014-09 is the
result of a joint effort by the FASB and the International Accounting Standards Board intended to clarify the principles for
recognizing revenue and to develop a common revenue standard for U.S. Generally Accepted Accounting Principles ("GAAP")
and International Financial Reporting Standards. ASU 2014-09 provides that an entity should recognize the amount of revenue to
which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 was originally intended
to be effective for annual periods and interim periods within that reporting period beginning after December 15, 2016, for public
business entities. In August 2015, the FASB issued ASU 2015-14 to defer the effective date of ASU 2014-09 for all entities by
one year. Public business entities will apply the guidance in ASU 2014-09 to annual reporting periods beginning after December
15, 2017 and interim periods within that reporting period. Early adoption of ASU 2014-09 is permitted after December 15, 2016.
The Company has not selected a transition method and is currently assessing the future impact of this ASU.

In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Topic 715) to simplify the presentation of
debt issuance costs. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance
sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and
measurement guidance for debt issuance costs are not affected by this ASU. ASU 2015-03 is effective for financial statements
issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. In August 2015, the FASB
issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30), to provide further clarification to ASU 2015-03 as it
relates to the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements. The
Company does not expect ASU 2015-03 and ASU 2015-15 to materially impact the Company's results of operations and cash
flows.

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 is currently assessing the future impact of this ASU.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and
Measurement of Financial Assets and Liabilities to enhance the reporting model for financial instruments by addressing certain
aspects of recognition, measurement, presentation, and disclosure. ASU 2016-01 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 unless the investments qualify for the new practicability exception. The guidance for classifying and
measuring investments in debt securities and loans are not changed by this ASU, but requires entities to record changes in instrument-
specific credit risk for financial liabilities measured under the fair value option in other comprehensive income. Financial assets
and financial liabilities must be separately presented by measurement category and form of financial asset on the balance sheet
or in the accompanying notes to the financial statements. ASU 2016-01 clarifies the need for a valuation allowance on a deferred
tax asset related to available-for-sale securities in combination with the entity's other deferred tax assets. The standard includes a
requirement that businesses must report changes in the fair value of their own liabilities in other comprehensive income instead
of earnings, and this is the only provision of the update for which the FASB is permitting early adoption. The remaining provisions
of this ASU become effective for public companies for fiscal years beginning after December 15, 2017, including interim periods
within those fiscal years. The Company is currently assessing the future impact of this ASU.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Regulation

General

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 increase in non-fuel base revenues
of approximately $71.5 million. The request includes recovery of new plant placed into service since 2009. On January 15, 2016,
the Company filed its rebuttal testimony modifying the requested increase to $63.3 million. The Company has invoked its statutory
right to have its new rates relate back for consumption on and after January 12, 2016, which is the 155th day after the filing. The
difference in rates that would have been collected will be surcharged or refunded to customers beginning after the PUCT's final
order in Docket No. 44941, which is expected to be in the second quarter of 2016. The PUCT has the authority to require the
Company to surcharge or refund such difference over a period not to exceed 18 months. On January 21, 2016, the Company, the
City of El Paso, the PUCT staff, the Office of Public Utility Counsel and the Texas Industrial Energy Consumers filed a joint
motion to abate the procedural schedule to facilitate settlement talks. This motion was granted. The Company cannot predict the
outcome of the rate case at this time.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Montana Power Station ("MPS") Approvals . The Company has received a Certificate of Convenience and Necessity ("CCN")
from the PUCT to construct four natural gas fired generating units at MPS in El Paso County, Texas. The Company also obtained
air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the U.S. Environmental Protection Agency
(the "EPA"). MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service
in March 2015.

Four Corners Generating Station ("Four Corners"). On February 17, 2015, the Company and Arizona Public Service
Company ("APS") entered into an asset purchase agreement (the "Purchase and Sale Agreement") providing for the purchase by
APS of the Company's interests in Four Corners. The Purchase and Sale Agreement included a projected cash purchase price which
will be equal to the net book value of our interest in Four Corners at the date of close. The net book value at June 30, 2016 is
expected to approximate $20 million. The Company will also be reimbursed for certain undepreciated capital expenditures, that
are projected to approximate $10 million at June 30, 2016. The purchase price will be adjusted downward to reflect APS's assumption
of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses estimated at July 6, 2016 to
be $7.0 million and $19.3 million, respectively.

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. The anticipated closing date of the sale is July 6,
2016, pending regulatory approval. This case was assigned PUCT Docket No. 44805. It is expected that the final coal mine closing
and reclamation costs, which the Company historically has been permitted to recover in its fuel recovery mechanism, will be
addressed in the proceeding, as well as other issues related to post-participation events such as the ARO. On January 11, 2016,
the PUCT referred the case to the State Office of Administrative Hearings ("SOAH") for an administrative hearing. On February
5, 2016, an administrative law judge ("ALJ") of the SOAH issued an order adopting a procedural schedule. The procedural schedule
calls for a hearing on the merits to be held in the fourth quarter of 2016. At December 31, 2015 the regulatory asset associated
with mine reclamation costs for our Texas jurisdiction approximates $7.6 million. At the PUCT's February 11, 2016 open meeting,
Commissioners discussed whether the Company's application should be addressed in a rate case. On February 11, 2016, the PUCT
issued its Order Requesting Briefing on Threshold Legal/Policy Issues, seeking briefs from the parties on the issue "Should the
Commission dismiss this docket?" Such briefs were due by February 22, 2016. The PUCT is expected to consider that issue at its
open meeting currently scheduled for March 3, 2016.

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

Public Utility Regulatory Act (the "PURA") and the PUCT.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

New Mexico Regulatory Matters

2015 New Mexico Rate Case Filing. On May 11, 2015, the Company filed with the NMPRC (NMPRC Case No. 15-00127-
UT) for an annual increase in non-fuel base rates of approximately $8.6 million or 7.1%. The request includes recovery of new
plant placed into service since the last time rates were adjusted in 2009. The filing also requests an annual reduction of $15.4
million, or 21.5%, for fuel and purchased power costs recovered in base rates. The reduction in fuel and purchased power rates
reflects reduced fuel prices and improvements in system heat rates due to new generating unit additions. Subsequently, the Company
reduced its requested increase in non-fuel base rates to approximately $6.4 million. On February 16, 2016, the Hearing Examiner
issued a Recommended Decision to the NMPRC proposing an annual increase in non-fuel base rates of approximately $640
thousand. On February 17, 2016, the NMPRC issued an order extending the suspension period in the rate case from March 10,
2016 until April 8, 2016, by which time the NMPRC is expected to either issue a final order with new rates to go into effect in the
second quarter of 2016 or again extend the suspension period further to as late as June 10, 2016. All parties will be allowed to file
exceptions before the NMPRC ultimately rules on the issues by final order. The Company cannot predict the outcome of the rate
case at this time.

Four Corners. On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for
the purchase by APS of the Company's interests in Four Corners. On April 27, 2015, the Company filed an application requesting
all necessary regulatory approvals to sell its ownership interest in Four Corners. The anticipated closing date of the sale is July
6, 2016, pending regulatory approval. This case was assigned NMPRC Case No. 15-00109-UT. On February 2, 2016, the Company
filed a joint stipulation with the NMPRC reflecting a settlement agreement among the Commission Utility Division Staff, the
Company and the New Mexico Attorney General proposing approval of abandonment and sale of its seven percent minority
ownership interest in Four Corners Units 4 and 5 and common facilities to APS. An addendum to the joint stipulation was
subsequently filed to include non-opposition by other non-stipulating parties. A hearing in the case was held on February 16, 2016,
and a final order approving the joint stipulation is expected in the first half of 2016. Based on the joint stipulation and addendum,
no significant gain or loss is expected to be realized upon closing of the sale.

5 MW Holloman Air Force Base ("HAFB") Facility CCN. On June 15, 2015, the Company filed a petition with the NMPRC
requesting CCN authorization to construct a 5 MW solar-powered generation facility to be located at HAFB in the Company's
service territory in New Mexico. The new facility will be a dedicated Company-owned resource serving HAFB. This case was
assigned NMPRC Case No. 15-00185-UT. On October 7, 2015, the NMPRC issued a Final Order accepting the Hearing Examiner’s
Recommended Decision to approve the CCN, as modified, that the Company shall not seek to recover any revenue requirement
associated with the facility from New Mexico jurisdictional customers other than HAFB without prior NMPRC approval.

Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case
No. 15-00280-UT to issue up to $310 million in new long-term debt; and to guarantee the issuance of up to $65 million of new
debt by Rio Grande Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel
debt obligations. This approval supersedes prior approvals.

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.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Federal Regulatory Matters

Public Service Company of New Mexico ("PNM") Transmission Rate Case. On December 31, 2012, PNM filed with FERC
to change its method of transmission rate recovery for its transmission delivery services from stated rates to formula rates. The
Company takes transmission service from PNM and is among the PNM transmission customers affected by PNM’s shift to formula
rates. On March 1, 2013, the FERC issued an order rejecting in part PNM’s filing, and establishing settlement judge and hearing
procedures. On March 20, 2015, PNM filed with FERC a settlement agreement and offer of settlement resolving all issues set for
hearing in the proceeding. On March 25, 2015, the Chief Judge issued an order granting PNM's motion to implement the settled
rates. However, the Company is still awaiting a final decision from the FERC on whether the settlement will be approved. The
Company cannot predict the outcome of the case at this time.

Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and

other approvals as required by the FERC.

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 and two presidential 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

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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 sheets are presented below (in
thousands):

Amortization
Period Ends

December 31,
2015

December 31,
2014

Regulatory assets

69,359

Regulatory tax assets (a) ........................................................
Loss on reacquired debt (c) .................................................... May 2035
Final coal reclamation (d) ......................................................

(b)

(e)

Nuclear fuel postload daily financing charge.........................
Unrecovered issuance costs due to reissuance of PCBs (c) ... August 2042
Texas energy efficiency..........................................................
Texas 2015 rate case costs......................................................

(e)

(f)
(g)

New Mexico procurement plan costs .....................................

New Mexico renewable energy credits ..................................

New Mexico 2010 FPPCAC audit .........................................

New Mexico Palo Verde deferred depreciation......................

New Mexico 2015 rate case costs ..........................................

Total regulatory assets

Regulatory liabilities

Regulatory tax liabilities (a) ...................................................

Accumulated deferred investment tax credit (h) ....................

New Mexico energy efficiency ..............................................

Texas military base discount and recovery factor ..................

Total regulatory liabilities

(g)

(b)

(g)

(b)

(f)

(i)

16,632

9,520

4,195

827

25
1,882

139

6,258

434

4,568

1,288

115,127

17,266

4,011

2,238

788

66,134

17,486

10,702

4,127

860

1,817
169

139

5,456

434

4,720

112,086

17,252

4,334

3,904

609

24,303

26,099

________________
(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 tariff.
(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 is excluded from rate base.
(i) This item represents the net asset/net liability related to the military discount which is recovered from non-military customers

through a recovery factor.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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, 2015 (in thousands):

Nuclear production ....................................................................... $
Steam and other ............................................................................
Total production ....................................................................
Transmission ................................................................................
Distribution...................................................................................
General .........................................................................................
Intangible......................................................................................

Gross
Plant
917,483
907,351
1,824,834
459,188
1,068,108
185,862
78,309
Total....................................................................................... $ 3,616,301

Accumulated
Depreciation

Net
Plant
613,423
596,270
1,209,693
202,289
714,395
131,869
28,212
$ (1,329,843) $ 2,286,458

(304,060) $
(311,081)
(615,141)
(256,899)
(353,713)
(53,993)
(50,097)

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 expected annual effect for 2016 is approximately
$3.6 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):

2013 ..................................................................................... $
2014 .....................................................................................
2015 .....................................................................................
2016 (estimated) ..................................................................
2017 (estimated) ..................................................................
2018 (estimated) ..................................................................
2019 (estimated) ..................................................................
2020 (estimated) ..................................................................

7,683
8,051
6,482
5,022
4,602
3,818
3,382
2,935

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.

Other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners and certain other transmission
facilities. A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31,
2015 and 2014 is as follows (in thousands):

Electric plant in service ............................................................... $
Accumulated depreciation ...........................................................
Construction work in progress.....................................................

Total...................................................................................... $

December 31, 2015

December 31, 2014

Palo Verde

917,483
(304,060)
48,938
662,361

Other
229,627
(181,886)
9,528
57,269

Palo Verde

874,817
(286,585)
55,632
643,864

Other
219,318
(176,492)
6,900
49,726

EL PASO ELECTRIC COMPANY
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 ("NRC"). 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.

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

Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company funds its share of the
estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective
operating licenses and is required to maintain a minimum accumulation and funding level in its decommissioning account at the
end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent
trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded.
At December 31, 2015, the Company’s decommissioning trust fund had a balance of $239.0 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 significant uncertainty. 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 million by the DOE to the Palo
Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On
October 8, 2014, the Company received approximately $9.1 million, representing its share of the award. The majority of the award
was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS acting on behalf of itself

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage
costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was $42.0 million. On June 1, 2015, the
Company received approximately $6.6 million, representing its share of the award. The majority of the award was credited to
customers through the applicable fuel adjustment clauses in March 2015. Thereafter APS will file annual claims for the period
July 1 of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for
the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. Funds related
to this claim are expected to be received in the second quarter of 2016. The Company's share of this claim is approximately $1.9
million.

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 at 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
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 its issuance 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 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

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014
final rule has been subject to continuing legal challenges before the NRC and the Court of Appeals.

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 DOE’s 2010 determination of the adequacy of the one tenth of a cent per kWh 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 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 ("Secretary") with instructions to conduct a new fee adequacy determination within six months. In February
2013, upon completion of 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 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 installation of equipment to address these requirements, but has minor additional
work to perform in 2016. Palo Verde has spent approximately $125 million (the Company's share is $19.7 million) on capital
enhancements related to these requirements as of December 31, 2015.

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 $13.5 billion. This potential liability is covered by
primary liability insurance provided by commercial insurance carriers in the amount of $375 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 $2.8 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 $12.7 million for the current policy period.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Four Corners

The Company owns a 7% interest in Units 4 and 5 at Four Corners and shares power entitlements and allocated costs with
APS, the operating agent, and the other Four Corners participants. The Company notified the other participants in 2013 that it
would not continue in Four Corners after the termination of the 50-year contractual term of the participation agreement in July
2016 but that it would offer to sell its interest to them in order to facilitate their decision to extend the life of the plant. On
February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by APS of
the Company’s interests in Four Corners. The cash purchase price is equal to the net book value of the Company’s interest in Four
Corners at the date of closing. The anticipated closing date for the sale is July 6, 2016, pending regulatory approval. See Part II,
Item 8, Financial Statements and Supplementary Data, Note C. The purchase price will be adjusted downward to reflect APS’s
assumption in the Agreement of the Company’s obligation to pay for future plant decommissioning and mine reclamation expenses.
At the closing, APS will also reimburse the Company for the undepreciated value of certain capital expenditures made prior thereto.
APS will assume responsibility for all capital expenditures made after July 2016 and, with certain exceptions, any pre-2016 capital
expenditures to be put into service following the closing. In addition, APS will indemnify the Company against liabilities and
costs related to the future operation of Four Corners. Included in the Company's balance sheet at December 31, 2015 are obligations
of $6.7 million and $19.3 million for plant decommissioning and mine reclamation costs, respectively, which the Company expects
to pay at closing in accordance with the Agreement. Four Corners is expected to continue to provide energy to serve the native
load up to the closing date. See Part II, Item 8, Financial Statements and Supplementary Data, Note C for a discussion of regulatory
filings associated with Four Corners.

Accounting for Asset Retirement Obligation

The Company complies with the FASB guidance for ARO. This guidance affects the accounting for the decommissioning
of the Company’s Palo Verde and Four Corners Stations 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, 2015 is $239.0 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:

Original ARO liability...............
Incremental ARO liability.........

Credit-Risk
Adjusted
Discount Rate

9.50%
6.20%

Escalation
Rate

3.60%
3.60%

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

An analysis of the activity of the Company’s total ARO liability from January 1, 2013 through December 31, 2015, including
the effects of each year’s estimate revisions, is presented below. In 2014, the estimate revision includes an adjustment to Four
Corners due to the early recognition of the obligation resulting from the purchase agreement with APS. In 2013, the estimate
revision includes a change to the probability of extending Four Corners’ operating term and decreases in the estimated cash flows
related to Palo Verde’s decommissioning due to implementing the 2013 Palo Verde decommissioning study.

ARO liability at beginning of year........................ $
Liabilities incurred .........................................
Liabilities settled............................................
Revisions to estimate .....................................
Accretion expense..........................................
ARO liability at end of year .................................. $

2015
74,577
189
—
—
6,855
81,621

2014
65,214
—
—
3,561
5,802
74,577

2013
62,784
—
(36)
(3,401)
5,867
65,214

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.

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.

Stock Options. Stock options have been granted at exercise prices equal to or greater than the market value of the underlying
shares at the date of grant. The fair value for these options was estimated at the grant date using the Black-Scholes option pricing
model. The options expired ten years from the date of grant unless terminated earlier by the Board of Directors (the “Board”).
Stock options have not been granted since 2003.

The 15,000 options outstanding at December 31, 2012 were exercised during 2013 with a weighted average exercise price
of $12.78. The Company received $0.2 million in cash and realized a current tax benefit of $0.1 million. The Company had no
stock options outstanding as of December 31, 2014 and December 31, 2015.

The intrinsic value of stock options exercised in 2013 was $0.3 million. No options were forfeited, vested or expired during

2015, 2014 and 2013. No compensation cost was recognized in 2015, 2014 and 2013 for stock options.

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.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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 2015, 2014 and 2013 is presented below (in thousands):

2015

2014

2013

Expense (a).......................................
Deferred tax benefit .........................
Current tax benefit recognized.........
_____________________
(a) Any capitalized costs related to these expenses is less than $0.3 million for all years.

1,215

2,755

3,471

964

2,458

860

109

The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in

2015, 2014 and 2013 is presented below (in thousands):

2015

2014

2013

Aggregated intrinsic value...........
Fair value at grant date ................

3,451

3,327

3,441

3,330

2,077

1,765

The unvested restricted stock transactions for 2015 are presented below:

Weighted
Average
Grant Date
Fair Value

Total
Shares

Unrecognized
Compensation
Expense (a)
(In thousands)

Aggregate
Intrinsic Value
(In thousands)

Restricted shares outstanding at December 31, 2014 .....

124,297

Stock awards............................................................

Vested ......................................................................

Forfeitures................................................................

Restricted shares outstanding at December 31, 2015 .....

72,187

(92,188)
(13,086)
91,210

35.81

37.17

36.09

35.76

36.61

1,397

3,512

_______________________
(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 2015,

2014 and 2013 were:

Weighted average fair value per share ............ $

37.17

36.95

35.48

2015

2014

2013

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.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Restricted Stock with a Performance Condition. On December 15, 2015, the Company issued a stock based retention grant
to the Chief Executive Officer of 27,624 shares in accordance with of the Company's 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
employment agreement. As of December 31, 2015, the adjusted grant date fair value for the award was $30.43, unrecognized
compensation expense was $0.7 million, and the intrinsic value was $1.1 million. For 2015, the Company recognized $6,000 as
compensation expense and $2,000 of deferred tax benefit related to this grant.

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

(In thousands)

Period
Compensation
Costs
Expensed

Aggregated
Intrinsic
Value

(In thousands)

January 27, 2016

February 20, 2015

February 18, 2014

January 29, 2013

150.0%

64,275

851

2013-2015

1,502

2012-2014

—

2011-2013

954

849

2010-2012

2,176

In 2016, 2017 and 2018, 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 2013 award, the actual number of shares to be issued can range from zero to
155,970 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 (a)

Aggregate
Intrinsic Value

(In thousands)

Performance shares outstanding at December 31, 2014...

121,481

Performance share awards ................................................

Performance shares expired..............................................
Performance shares forfeited ............................................
Performance shares outstanding at December 31, 2015...

52,948
(57,299)
(14,618)
102,512

30.71

35.72
29.51
35.13

33.34

1,112

3,947

_______________________
(a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term

of the awards of approximately one year.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

A summary of information related to performance shares for 2015, 2014 and 2013 is presented below:

2015

2014

2013

Weighted average per share grant date fair value per share of
performance shares awarded ....................................................................... $
Fair value of performance shares vested (in thousands) .............................
Intrinsic value of performance shares vested (in thousands) (a) .................
Compensation expense (in thousands) (b)...................................................
Deferred tax benefit related to compensation expense (in thousands) ........

35.72

26.36

34.69

—

1,042

365

—

1,181

413

849

1,450

1,188

416

_____________________
(a) Based on a 100% performance level.
(b) Includes adjustments for forfeiture of performance share awards by certain executives.

Repurchase Program

No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2015. Detail

regarding the Company's stock repurchase program are presented below:

Shares repurchased (b) ................................................................................
Cost, including commission (in thousands) ................................................ $
Total remaining shares available for repurchase at December 31, 2015.....

Since 1999
(a)

25,406,184

423,647

Authorized
Shares

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
108,085 shares out of treasury stock during 2015.

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, 2015, the Company paid $11.9 million in quarterly cash dividends to shareholders. The Company paid a
total of $47.1 million, $44.6 million and $42.0 million in cash dividends during the twelve months ended December 31, 2015,
2014 and 2013, respectively. On January 28, 2016, the Board of Directors declared a quarterly cash dividend of $0.295 per share
payable on March 31, 2016 to shareholders of record as of the close of business on March 15, 2016.

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,
2014

2013

2015

Weighted average number of common shares outstanding:

Basic number of common shares outstanding ...............................................
Dilutive effect of unvested performance awards ...................................
Diluted number of common shares outstanding ............................................

40,274,986
33,576
40,308,562

40,190,991
20,726
40,211,717

40,114,594
12,053
40,126,647

Basic net income per common share:

Net income ..................................................................................................... $
Income allocated to participating restricted stock .........................................

Net income available to common shareholders ...................................... $

Diluted net income per common share:

Net income ..................................................................................................... $
Income reallocated to participating restricted stock ......................................

Net income available to common shareholders ...................................... $

Basic net income per common share:

Distributed earnings ....................................................................................... $
Undistributed earnings ...................................................................................

Basic net income per common share ...................................................... $

Diluted net income per common share:

Diluted net income per common share ................................................... $

81,918
(243)
81,675

1.165
0.865
2.030

91,428
(301)
91,127

1.105
1.165
2.270

88,583
(254)
88,329

1.045
1.155
2.200

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:

Restricted stock awards ............................................

Year Ended December 31,
2014
60,455

2015
56,375

2013
51,489

Performance shares (a) .............................................

66,804

96,208

115,044

_____________________
(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.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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, 2012............................ $

(75,737) $

22,194

(12,541)

(66,084)

Other comprehensive income before

reclassifications..........................................

51,371

14,482

Amounts reclassified from accumulated other
comprehensive income (loss)...................

Balance at December 31, 2013............................

Other comprehensive income (loss) before

reclassifications..........................................
Amounts reclassified from accumulated other
comprehensive income (loss)...................
Balance at December 31, 2014............................
Other comprehensive income (loss) before

reclassifications..........................................

Amounts reclassified from accumulated other
comprehensive income (loss)...................

Balance at December 31, 2015............................ $

3,036

(21,330)

(12,628)

(926)
(34,884)

3,777

(436)

36,240

8,694

(5,977)
38,957

(2,255)

—

243

(12,298)

—

224
(12,074)

—

65,853

2,843

2,612

(3,934)

(6,679)
(8,001)

1,522

1,238
(29,869) $

(8,937)
27,765

264
(11,810)

(7,435)
(13,914)

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Amounts reclassified from accumulated other comprehensive income (loss) for the twelve months ended December 31,

2015, 2014 and 2013 are as follows (in thousands):

Details about Accumulated Other
Comprehensive Income (Loss)
Components

Amortization of pension and post-

retirement benefit costs:
Prior service benefit .............................
Net loss.................................................

Income tax effect..................................

2015

2014

2013

Affected Line Item
in the Statement of
Operations

6,574

(8,622)

(2,048)

810

(1,238)

7,659
(6,182)
1,477
(551)
926

5,560 (a)
(10,472) (a)
(4,912) (a)
1,876
(3,036) (a)

Marketable securities:

Net realized gain on sale of securities..

11,114

7,350

Income tax effect..................................

11,114

(2,177)

8,937

7,350
(1,373)
5,977

553

Investment and
interest income, net
Income before
income taxes
553
(117) Income tax expense
436 Net income

Loss on cash flow hedge:

Amortization of loss.............................

Income tax effect..................................

(467)

203

(264)

(438)

(438)
214
(224)

Interest on long-
term debt and RCF

(411)

Income before
income taxes

(411)
168 Income tax expense
(243) Net income

Total reclassifications...........................

7,435

6,679

(2,843)

(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.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Long-Term Debt and Financing Obligations

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

Long-Term Debt:

Pollution Control Bonds (1):

7.25% 2009 Series A refunding bonds, due 2040 (7.46% effective interest rate)............ $
4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate)............
7.25% 2009 Series B refunding bonds, due 2040 (7.49% effective interest rate)............
1.875% 2012 Series A refunding bonds, due 2032 (2.35% effective interest rate)..........
Total Pollution Control Bonds.................................................................................

Senior Notes (2):

6.00% Senior Notes, net of discount, due 2035 (7.12% effective interest rate)...............
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)...............
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)...............
5.00% Senior Notes, net of discount, due 2044 (5.10% effective interest rate)...............
Total Senior Notes...................................................................................................

RGRT Senior Notes (3):

December 31,

2015

2014

(In thousands)

63,500
59,235
37,100
33,300
193,135

398,069
148,838
149,766
149,476
846,149

63,500
59,235
37,100
33,300
193,135

398,021
148,818
149,737
149,468
846,044

3.67% Senior Notes, Series A, due 2015 (3.87% effective interest rate).........................
4.47% Senior Notes, Series B, due 2017 (4.62% effective interest rate).........................
5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate).........................
Total RGRT Senior Notes.......................................................................................
Total long-term debt.......................................................................................

—
50,000
45,000
95,000
1,134,284

15,000
50,000
45,000
110,000
1,149,179

Financing Obligations:

Revolving Credit Facility ($141,738 due in 2016) (4) ............................................................
Total long-term debt and financing obligations......................................................

141,738
1,276,022

14,532
1,163,711

Current Portion (amount due within one year):

Current maturities of long term debt ................................................................................
Short-term borrowings under the revolving credit facility...............................................

—
(141,738)
$ 1,134,284

(15,000)
(14,532)
$ 1,134,179

_____________________
(1) 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.

(2) Senior Notes

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

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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

The 3.30% Senior Notes have an aggregate principal amount of $150.0 million and 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.

The 5.00% Senior Notes have an aggregate principal amount of $150.0 million and were issued in December 2014. The
proceeds, net of a $0.5 million discount, were used to fund construction expenditures and for working capital and general
corporate purposes.

(3) RGRT Senior Notes

In 2010, the Company and RGRT, a Texas grantor trust through which the Company finances its portion of fuel for Palo Verde,
entered into a note purchase agreement with various institutional purchasers. Under the terms of the agreement, RGRT sold
to the purchasers $110 million aggregate principal amount of Senior Notes (the "Notes"). In August 2015, $15.0 million of
these Notes matured and were paid with borrowings from the RCF. The Company guarantees the payment of principal and
interest on the Notes. In the Company’s financial statements, the assets and liabilities of the 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 2015.

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 revolving credit facility 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.

(4) Revolving Credit Facility

On January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the
RCF with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication
agent, and various lending banks party thereto. Under the terms of the agreement, the Company has available $300 million
and the ability to increase the RCF by up to $100 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 has a term ending January 2019. The Company may extend the maturity date up to two times, in each
case for an additional one year period upon the satisfaction of certain conditions.

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 2015. 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 RFC. As of December 31, 2015, the total amount borrowed by RGRT was
$33.7 million for nuclear fuel under the RCF. As of December 31, 2015, $108.0 million of borrowings were outstanding
under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was
1.4% as of December 31, 2015.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

As of December 31, 2015, the scheduled maturities for the next five years of long-term debt are as follows (in thousands):

2016....................................................... $
2017.......................................................
2018.......................................................
2019.......................................................
2020.......................................................

—
83,300
—
—
45,000

The $33.7 million outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2016.

Income Taxes

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at

December 31, 2015 and 2014 are presented below (in thousands):

December 31,

2015

2014

Deferred tax assets:

Benefit of tax loss carryforwards ............................................................................................ $
Alternative minimum tax credit carryforward.........................................................................
Pensions and benefits ..............................................................................................................
Asset retirement obligation......................................................................................................
Deferred fuel............................................................................................................................
Other ........................................................................................................................................
Total gross deferred tax assets..........................................................................................

35,153
16,620
61,673
28,042
1,488
15,421
158,397

—
17,701
64,407
25,725
—
15,768
123,601

Deferred tax liabilities:

Plant, principally due to depreciation and basis differences ...................................................
Decommissioning ....................................................................................................................
Deferred fuel............................................................................................................................
Other ........................................................................................................................................
Total gross deferred tax liabilities ....................................................................................

Net accumulated deferred income taxes ................................................................. $

(608,738)
(41,100)
—
(3,796)
(653,634)
(495,237) $

(536,264)
(40,373)
(3,531)
(3,630)
(583,798)
(460,197)

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.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The Company recognized income tax expense for 2015, 2014 and 2013 as follows (in thousands):

Years Ended December 31,

2015

2014

2013

Income tax expense:

Federal:

Current .................................................................................................... $
Deferred ..................................................................................................
Total federal income tax................................................................

State:

Current ....................................................................................................
Deferred ..................................................................................................
Total state income tax....................................................................
Generation (amortization) of accumulated investment tax credits ................

Total income tax expense............................................................... $

2,319
32,819
35,138

1,730
(1,650)
80
(323)
34,895

(1,250) $
38,810
37,560

3,209
641
3,850
(322)
41,088

(2,877)
45,024
42,147

1,854
(414)
1,440
68
43,655

As of December 31, 2015, the Company had $16.6 million of AMT credit carryforwards that have an unlimited life. As of
December 31, 2015, the Company had $34.1 million of federal and $1.1 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.

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):

Federal income tax expense computed on income at statutory rate...................... $
Difference due to:

State taxes, net of federal benefit...................................................................
AEFUDC .......................................................................................................

Permanent tax differences..............................................................................
Other ..............................................................................................................

Total income tax expense............................................................... $

Years Ended December 31,

2015
40,885

2014
46,381

2013
46,283

(2,345)
(2,898)
(799)
34,895

1,902

(3,757)
(2,921)
(517)
41,088

936

(2,149)
(1,153)
(262)
43,655

Effective income tax rate ......................................................................................

29.9%

31.0%

33.0%

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

On December 18, 2015, the President signed the Protecting Americans from Tax Hikes Act of 2015. This act included the
extension of bonus depreciation and certain credits which impacted the Company. The Company recorded the impacts of the law
change in December 2015, which did not have a material impact on the financial position of the Company.

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. In January 2010, the Company filed for a change
of accounting method with the Internal Revenue Service ("IRS") related to the way in which units of property are determined for
purposes of determining capitalized tax assets. The change was included in the 2009 federal income tax return, with additional
amounts included in the 2010 to 2013 federal income tax returns. In 2013, a $4.5 million decrease was made to the reserve related
to the change in accounting method. The decrease was primarily the result of the completion of IRS audits for tax years 2009 to
2012. In September 2014, the Company received an Issue Resolution Agreement ("IRA") from IRS regarding the generation
repairs deduction for all years. In the IRA, the IRS declared that the method used by the Company to calculate the generation
repair deduction was substantially the same as the method outlined in the Revenue Procedure and declared that therefore no

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

adjustment to the deduction taken in previous tax returns by the Company was required. As a result of the IRA, in 2014 the
Company recorded a $2.8 million decrease to eliminate the balance of the reserve related to the change in accounting method.
The Company recorded an unrecognized tax position of $0.8 million, $2.1 million, and $0.5 million in 2015, 2014, and 2013,
respectively, related to depreciation and other amounts deducted in current and prior year Texas franchise tax returns. The Company
recorded a decrease of $1.3 million (net of an increase of $0.4 million) in 2014 and an increase of $1.3 million (net of a decrease
of $0.4 million) in 2013 related to tax credits taken in prior year Arizona income tax returns, which have been settled through
audit. A reconciliation of the December 31, 2015, 2014 and 2013 amounts of unrecognized tax benefits are as follows (in thousands):

Balance at January 1 ............................................................................................. $
Additions for tax positions related to the current year...................................
Reductions for tax positions related to the current year ................................
Additions for tax positions of prior years ......................................................
Reductions for tax positions of prior years ....................................................
Balance at December 31 ....................................................................................... $

2015

2014

2013

5,200
500
—
300
—
6,000

7,200
300
—
2,200
(4,500)
5,200

9,800
600
—
1,700
(4,900)
7,200

If recognized, $3.6 million of the unrecognized tax position at December 31, 2015, would affect the effective tax rate. The
Company recognized income tax expense for an unrecognized tax position of $0.8 million for the year ended December 31, 2015.

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. For the
years ended December 31, 2015, 2014, and 2013 the Company recognized interest expense of $0.2 million, $0.1 million, and $0.2
million, respectively. The Company had approximately $0.7 million and $0.5 million accrued for the payment of interest and
penalties at December 31, 2015 and 2014, respectively.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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:

Type of Contract

Counterparty

Quantity

Term

Power Purchase and Sale Agreement .

Freeport

Power Purchase Agreement................

Hatch Solar Energy Center
I, LLC

25 MW

December 2008 through December
2016

100 MW

June 2006 through December 2021

5 MW

July 2011 through June 2036

July 2011

Commercial

Operation

Date

N/A

Power Purchase Agreement................

NRG

20 MW

August 2011 through August 2031

August 2011

Power Purchase Agreement................

SunE EPE1, LLC

Power Purchase Agreement................

SunE EPE2, LLC

10 MW

12 MW

June 2012 through June 2037

May 2012 through May 2037

June 2012

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 2016.

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. This solar photovoltaic plant began commercial operation in December 2014.

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. 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.

Clean Air Interstate Rule/Cross State Air Pollution Rule. The EPA promulgated the Cross-State Air Pollution Rule ("CSAPR")
in August 2011, which rule involves requirements to limit emissions of 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"). While the U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit")
vacated CSAPR in August 2012 and allowed CAIR to stand until the EPA issued a proper replacement, on April 29, 2014, the U.S.
Supreme Court reversed and upheld CSAPR, remanding certain portions of CSAPR to the D.C. Circuit for further consideration.
On June 26, 2014, the EPA filed a motion asking the D.C. Circuit to lift its stay on CSAPR, and on October 23, 2014, the D.C.
Circuit lifted its stay of CSAPR. On July 28, 2015, the D.C. Circuit ruled that the EPA's emissions budgets for 13 states including
Texas are invalid but left the rule in place on remand. On December 3, 2015, EPA published the proposed CSAPR Update Rule
with a 60-day public comment period. While we are unable to determine the full impact of this decision until EPA takes further
action, the Company believes it is currently positioned to comply with CSAPR.

National Ambient Air Quality Standards ("NAAQS"). Under the 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 expected to make attainment/nonattainment designations for the revised
ozone standards by October 1, 2017. While it is currently unknown how the areas in which we operate will be designated, for
nonattainment areas classified as "Moderate" and above, states, and any tribes that choose to do so, are expected to be required to
complete development of implementation plans in the 2020-2021 timeframe. Most nonattainment areas are expected to have until
2020 or 2023 to meet the primary (health) standard, with the exact attainment date varying based on the ozone level in the area.
The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company
is required to install additional equipment to control emissions at its facilities, the NAAQS, individually or in the aggregate, could
have a material impact on its operations and financial results.

Mercury and Air Toxics Standards. The operation of coal-fired power plants, such as Four Corners, results in emissions of
mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "MATS Rule")
for oil-and coal-fired power plants, which requires significant reductions in emissions of mercury and other air toxics. Several
judicial and other challenges have been made to this rule, and on June 29, 2015, the U.S. Supreme Court remanded the rule to the
D.C. Circuit Court. On December 15, 2015, the D.C. Circuit Court issued an order remanding the rule to EPA but did not vacate
the rule during remand. EPA expects to issue a revised “appropriate and necessary” finding by April 15, 2016. The legal status of
the MATS Rule notwithstanding, the Four Corners plant operator, APS, believes Units 4 and 5 will require no additional
modifications to achieve compliance with the MATS Rule, as currently written. We cannot currently predict, however, what
additional modifications or costs may be incurred if the EPA rewrites the MATS Rule on remand.

Other Laws and Regulations and Risks. The Company has entered into an agreement to sell its interest in Four Corners to
APS at the expiration of the 50-year participation agreement in July 2016. The Company believes that it has better economic and
cleaner alternatives for serving the energy needs of its customers than coal-fired generation, which is subject to extensive regulation
and litigation. By ceasing its participation in Four Corners, the Company expects to avoid the significant cost required to install

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

expensive pollution control equipment in order to continue operation of the plant as well as the risks of water availability that
might adversely affect the amount of power available, or the price thereof, from Four Corners in the future. The closing of the
transaction is subject to the receipt of regulatory approvals (see Part II, Item 8, Financial Statements and Supplementary Data,
Note C).

Coal Combustion Waste. On October 19, 2015 the EPA's final rule regulating the disposal of coal combustion residuals (the
"CCR Rule") from electric utilities as solid waste took effect. The Company has a 7% ownership interest in Units 4 and 5 of Four
Corners, the only coal-fired generating facility for which the Company has an ownership interest subject to the CCR Rule. The
Company entered into a Purchase and Sale Agreement with APS in February 2015 to sell the Company’s entire ownership interest
in Four Corners. The CCR Rule requires plant owners to treat coal combustion residuals as Subtitle D (as opposed to a more costly
Subtitle C) waste. In general, the Company is liable for only 7% of costs to comply with the CCR Rule (consistent with our
ownership percentage). The Company, however, believes under the terms of the Purchase Agreement and after the pending sale,
as a former owner, that the Company is not responsible for a significant portion of the costs under the CCR Rule, such as ongoing
operational costs after July 2016. Accordingly, the Company does not expect the CCR Rule to have a significant impact on our
financial condition or results of operations.

On November 3, 2015, the EPA published a final rule revising wastewater effluent limitation guidelines for steam electric
power generators (the "Revised ELG Rule"). The Revised ELG Rule establishes requirements for wastewater streams from certain
processes at affected facilities, including limits on toxic metals in wastewater discharges. Facilities must comply with the Revised
ELG Rule between 2018 and 2023. The EPA anticipates that the new requirements in the Revised ELG Rule will only affect certain
coal-fired steam electric power plants. Because the Company is not expected to have an interest in Four Corners after July 2016,
the Company does not expect the Revised ELG Rule will have a significant impact on our financial condition or results of operations.

In 2012, several environmental groups filed a lawsuit in federal district court against the Office of Surface Mining Reclamation
and Enforcement ("OSM") of the U.S. Department of the Interior challenging OSM’s 2012 approval of a permit revision which
allowed for the expansion of mining operations into a new area of the mine that serves Four Corners ("Area IV North"). In April
2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM takes
action to cure the defect in its permitting process identified by the court. On December 29, 2015, OSM took action to cure the
defect in its permitting process by issuing a revised environmental assessment and finding of no new significant impact, and
reissued the permit. This action is subject to possible judicial review.

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 2015, the
United States participated in the United Nations Conference on Climate Change, which led to creation of the Paris Agreement.
The Paris Agreement will be open for signing on April 22, 2016 and will require 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. After announcing
his plan to address climate change in 2013, the President directed the EPA to issue proposals for GHG rulemaking addressing
power plants. In October 2015, the EPA published a final rule establishing new source performance standards ("NSPS") limiting
CO2 emissions from new, modified and reconstructed electric generating units. In October 2015, the EPA also published a rule
establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to
address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. The standards for
existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved
beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP 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. 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.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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, reduced 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, financial condition, reputation 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 2009, the EPA and certain environmental organizations have been
scrutinizing, and in some cases, have filed lawsuits, relating to certain air emissions and air permitting matters related to Four
Corners. In particular, since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the EPA, and APS have been
engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The allegations being addressed
through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the
CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under Title V of the CAA that reflects
applicable requirements imposed by law. In November 2014, the DOJ provided APS with a draft consent decree to settle the EPA
matter, which decree contains specific provisions for the reduction and control of NOx, SO2, and PM, as well as provisions for a
civil penalty, and expenditures on environmental mitigation projects with an emphasis on projects that address alleged harm to
the Navajo Nation. On June 24, 2015, the parties filed with the U.S. District Court for New Mexico a settlement agreement ("CAA
Settlement Agreement") resolving this matter. On August 17, 2015, the U.S. District Court for New Mexico entered the CAA
Settlement Agreement. The agreement imposes a total civil penalty payable by the co-owners of Four Corners collectively in the
amount of $1.5 million, and it requires the co-owners to pay $6.7 million for environmental mitigation projects. At December 31,
2015, the Company has accrued for its share of approximately $0.5 million related to this matter.

In a related action, on October 4, 2011, Earthjustice filed a lawsuit in the United States District Court for New Mexico
alleging violations of the Prevention of Significant Deterioration ("PSD") provisions of the CAA related to Four Corners. Thereafter,
on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's NSPS program. The
lawsuit addressed allegations similar to those raised in the DOJ pre-enforcement action described in the preceding paragraph.
Because the allegations in the DOJ pre-enforcement action and this lawsuit were substantially similar, the negotiations between
the DOJ and APS regarding the pre-enforcement action also included Earthjustice. Accordingly, in response to the CAA Settlement
Agreement, the parties to the case moved to dismiss the proceedings. Accordingly, the proceedings were terminated as of August
17, 2015. The CAA Settlement Agreement represents the final judgment in this case.

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 million related to coal supplied under the coal supply agreement
for Four Corners (the "Assessment"). The Company's share of the assessment was 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 participants receive a refund of all the contested amounts previously
paid under the applicable tax statue. The NMTRD filed a Notice of Appeal on August 31, 2015 with respect to the decision. The
parties are engaged in settlement discussions and the Company does not expect the outcome to have a material impact on the
Company's financial position, results of operations or cash flows.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Lease Agreements

The Company leases land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with
a renewal option of 25 years. In addition, the Company leased certain warehouse facilities in El Paso under a lease which expired
in December 2015. The Company also has several other leases for office, parking facilities and equipment which expire within
the next five 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 $1.9 million, $1.8 million, and $1.2 million for
2015, 2014 and 2013, respectively. As of December 31, 2015, the Company’s minimum future rental payments for the next five
years are as follows (in thousands):

2016................................................. $
2017.................................................
2018.................................................
2019.................................................
2020.................................................

900
648
538
541
548

Litigation

See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note K for discussion of the effects of

government legislation and regulation on the Company as well as certain pending legal proceedings.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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 at least the minimum funding amounts required by the IRS, 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.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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

December 31,

2015

2014

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................ $
Service cost.........................................................
Interest cost.........................................................
Amendments (a)..................................................
Actuarial (gain) loss............................................
Benefits paid .......................................................
Benefit obligation at end of year .................

Change in plan assets:

Fair value of plan assets at end of prior year ......
Actual return (loss) on plan assets ......................
Employer contribution ........................................
Benefits paid .......................................................
Fair value of plan assets at end of year........
Funded status at end of year ........................ $

341,133
8,530
13,477
—
(19,290)
(18,144)
325,706

272,939
(3,760)
9,000
(18,144)
260,035
(65,671) $

28,397
262
1,018
—
(810)
(1,909)
26,958

—
—
1,909
(1,909)
—
(26,958) $

317,815
8,284
14,001
(33,700)
50,741
(16,008)
341,133

257,831
22,116
9,000
(16,008)
272,939
(68,194) $

25,898
303
1,041
(500)
3,508
(1,853)
28,397

—
—
1,853
(1,853)
—
(28,397)

_____________________
(a) Amendments relate to the modification of the Company’s Retirement Plan and Excess Benefit Plan discussed above.

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

December 31,

2015

2014

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Current liabilities ......................................................................... $
Noncurrent liabilities ...................................................................

Total...................................................................................... $

— $

(65,671)
(65,671) $

(2,102) $
(24,856)
(26,958) $

— $

(68,194)
(68,194) $

(2,319)
(26,078)
(28,397)

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

December 31,

2015

2014

Retirement
Income
Plan
(325,706) $
(302,446)
260,035

Non-Qualified
Retirement
Plans

(26,958) $
(25,785)
—

Retirement
Income
Plan
(341,133) $
(312,762)
272,939

Non-Qualified
Retirement
Plans

(28,397)
(27,603)
—

Projected benefit obligation......................................................... $
Accumulated benefit obligation ..................................................
Fair value of plan assets ..............................................................

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Amounts recognized in accumulated other comprehensive income consist of the following (in thousands):

Net loss ........................................................................................ $
Prior service benefit.....................................................................

Total...................................................................................... $

Years Ended December 31,

2015

2014

Retirement
Income
Plan
118,963
(27,344)
91,619

Non-Qualified
Retirement
Plans

9,592
(224)
9,368

Retirement
Income
Plan
124,407
(30,811)
93,596

Non-Qualified
Retirement
Plans

11,341
(264)
11,077

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

December 31,

2015

Non-Qualified

2014

Non-Qualified

Retirement
Income
Plan

Supplemental
Retirement
Plan

Excess
Benefit
Plan

Retirement
Income
Plan

Supplemental
Retirement
Plan

Excess
Benefit
Plan

Discount rate ............................
Rate of compensation increase .

4.57%
4.5%

3.99%
N/A

4.59%
4.5%

4.0%
4.5%

3.4%
N/A

4.1%
4.5%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each
measurement date. For 2015, 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, 2015 retirement plans' projected
benefit obligation by 11.4%. A 1% decrease in the discount rate would increase the December 31, 2015 retirement plans' projected
benefit obligation by 14%.

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

Years Ended December 31,

2015

2014

2013

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

8,530
13,477
(19,795)

262
1,018
—

8,284
14,001
(18,699)

303
1,041
—

9,137
12,742
(17,108)

9,710
(3,467)

937
(39)

8,178
(2,889)

675
(17)

10,437
3

190
872
—

661
94

8,455

2,178

8,875

2,002

15,211

1,817

Service cost .............................. $
Interest cost ..............................
Expected return on plan assets.
Amortization of:

Net loss .............................
Prior service cost (benefit)
Net periodic benefit
cost............................. $

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

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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

2015

2014

2013

Years Ended December 31,

Net (gain) loss .......................... $
Prior service benefit .................
Amortization of:

Net loss..............................
Prior service (cost) benefit
Total recognized in other
comprehensive income...... $

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

4,266
—

(811) $
—

47,324
(33,700)

3,508
(500)

Retirement
Income
Plan
(30,065) $
—

Non-Qualified
Retirement
Plans

(9,710)
3,467

(937)
39

(8,178)
2,889

(675)
17

(10,437)
(3)

(1,977) $

(1,709) $

8,335

2,350

(40,505) $

(1,288)

(533)
—

(661)
(94)

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

thousands):

Years Ended December 31,

2015

2014

2013

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 ............. $

6,478

469

17,210

4,352

(25,294) $

529

The following are amounts in accumulated other comprehensive income that are expected to be recognized as

components of net periodic benefit cost during 2016 (in thousands):

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Net loss ........................................................................................................................................... $
Prior service benefit........................................................................................................................

6,830
(3,470)

715
(40)

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the

twelve months ended December 31:

2015

Non-Qualified

2014 (a)

Non-Qualified

2013

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

4.0%

3.4% 4.1%

4.9%

3.9%

4.9%

4.0%

3.1%

4.0%

7.5%

N/A

7.5%

N/A

7.5%

N/A

4.5%

N/A

4.5%

4.75%

N/A

4.75%

N/A

4.75%

Discount rate......

Expected long-
term return on
plan assets..........

Rate of
compensation
increase ..............

_____________________
(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.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The Company’s overall expected long-term rate of return on assets is 7.5% effective January 1, 2015, and 7.0% effective
January 1, 2016, 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:

Equity securities ..............................
Fixed income ...................................
Alternative investments ...................
Total......................................

December 31, 2015

50%

40%

10%

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.

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 Common Collective Trusts are valued using the net asset value ("NAV") provided by the
administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded
on active markets.

Level 3 – Unobservable inputs using data that is not corroborated by market data. The fair value of the real estate limited
partnership is reported at the NAV of the investment.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The fair value of the Company’s Retirement Plan assets at December 31, 2015 and 2014, 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
Cash and Cash Equivalents ......................................................... $
Common Collective Trusts (a)

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)

1,266

— $

—

Equity funds .............................................................................
Fixed income funds..................................................................
Real Estate Funds.....................................................................
Total Common Collective Trusts..........................................
Limited Partnership Interest in Real Estate (b) ...........................

Total Plan Investments ......................................................... $

144,279
103,877
2,025
250,181
8,588
260,035

—
—
—
—
—
1,266

144,279
103,877
2,025
250,181
—
250,181

—
—
—
—
8,588
8,588

Description of Securities
Cash and Cash Equivalents ......................................................... $
Common Collective Trust (a)

Fair Value as of
December 31,
2014

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

1,237

— $

—

Equity funds .............................................................................
Fixed income funds..................................................................
Total Common Collective Trusts..........................................
Limited Partnership Interest in Real Estate (b) ...........................

Total Plan Investments ......................................................... $

149,839
113,115
262,954
8,748
272,939

—
—
—
—
1,237

149,839
113,115
262,954
—
262,954

—
—
—
8,748
8,748

_____________________
(a) The Common Collective Trusts are invested in equity and fixed income securities, or a combination thereof. The investment

objective of each trust 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 is restricted from selling its partnership interest during the life of the partnership
which is generally 5-7 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 table below reflects the changes in the fair value of investments in the real estate limited partnership during the period

(in thousands):

Balances at December 31, 2013 .................................................................................. $
Sale of land...........................................................................................................
Unrealized gain in fair value ................................................................................
Balances at December 31, 2014 ..................................................................................
Unrealized loss in fair value.................................................................................
Balances at December 31, 2015 .................................................................................. $

8,857
(357)
248
8,748
(160)
8,588

Fair Value of
Investments in
Real Estate

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, 2015 and 2014. Except as noted in the above table, 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, 2015 and 2014.

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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 $6.2 million to its retirement plans in 2016.

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

2016 ........................................................................... $
2017 ...........................................................................
2018 ...........................................................................
2019 ...........................................................................
2020 ...........................................................................
2021-2025..................................................................

12,502
13,752
14,973
16,141
17,210
100,358

2,102
2,069
2,059
2,024
1,985
9,151

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 2015, 2014 and 2013 were $3.9 million, $3.0 million, and $1.9 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.