Excelerate Energy

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2018 was an exceptional year for El Paso Electric Company, 
(“EE” or the “Company”), as we were able to make significant 
advances that will enable us to expand and improve our service 
options and prepare for the energy and sustainability future of 
our community. 

In response to growing customer demand in our service territory, 
EE issued an All Source Request for Proposals (“RFP”) in 2017 
for 370 megawatts of additional generation resources that will  
be needed by the 2023 summer peak season. Resource 
planning is key to meeting the future energy needs of our growing 
region, and the planning and selection process ensures that the 
Company chooses the optimal mix of long-term, affordable 
and reliable electric resources. After extensive evaluation 
of numerous proposals, we announced the results of the RFP 
at the end of 2018 with a diversified mix of resource additions, 
which are comprised of 200 megawatts (“MW”) of utility scale 
solar, 100 MW of battery storage, and a 226 MW natural gas 
combustion turbine. Additionally, we expect to pursue the 
purchase of 50 to 150 MW of wind and solar generated power 
for fuel diversity and energy cost savings in the future. This mix  
of new capacity emphasizes our strategic goal of planning for  
the future while advancing in renewable energy sources and  
cleaner technologies. In addition to this expansion of future 
resources, EE is continuing to invest in local generation 
programs to support the long-term reliability of our power 
generation assets. 

We were also pleased to see our goal to add renewable 
resources in a responsible and cost-effective manner 
and achieved another milestone when we celebrated the 
commercial operation of the Holloman Air Force Base Solar 
Facility in October 2018. The 42-acre Holloman Atlas Solar 
Array is the first customer-dedicated resource that EE has 
built to serve a U.S. military installation. The output from the 
five MW solar facility generates enough electricity to power 
more than 1,700 homes annually and helps the Air Force meet 
its renewable and energy security goals. In addition, in March 
2018, we filed for approval to expand our Texas Community Solar 
Program to include two MW of solar-powered generation from  
a 10 MW solar facility located at the Company’s Newman  
Power Station in El Paso, TX.

In August 2018, we released our first annual Corporate 
Sustainability Report, celebrating a major milestone for 
our Company. As we recognized the need to transparently 
communicate our efforts and achievements regarding our 
environmental and corporate sustainability initiatives, we 
developed a report that highlights these accomplishments, 
including our divestment from coal, our efforts in energy 
efficiency, our impactful internship programs, and our 
partnerships with local organizations. We are committed to 
establishing long-term goals to further improve our carbon 
footprint and continue reporting on our progress through  
future Corporate Sustainability Reports. 

As we look forward to the potential for adding new technologies 
and the opportunity to improve customer service, we are 
pleased to have engaged our local leaders and our community 
in 2018 to discuss the benefits of implementing Advanced 
Metering Infrastructure or AMI, which is the backbone of 
a smart community. We are excited to continuing these 
discussions, and to build a business case that would allow us to 
make investments to modernize our electric grid that will further 
improve our operational efficiency, while expanding customer 
products and services such as smart pricing options, high 
usage alerts, and online energy management tools.

2019 will also be an important year in terms of our regulatory 
objectives. We have filed our requests in Texas for a Transmission 
Cost Recovery Factor and a Distribution Cost Recovery Factor, 
which allow us to recover on the capital investments we have 
made in transmission and distribution infrastructure in a timely 
manner. Additionally, in 2019, we will be filing a general rate 
case in New Mexico, as well as a general rate case with the 
Federal Energy Regulatory Commission. 

Our accomplishments over the previous year and future 
objectives are all possible due to the dedication and hard 
work of our employees. We cannot serve our customers 
reliably and effectively without the valued contributions of 
our International Brotherhood of Electrical Workers local 960 
team members, who represent approximately 37% of our 
local workforce. In 2018, we achieved our highest customer 
service ratings since we began surveying customers in 2009 
to measure their satisfaction with the level of service they 
receive. In September 2018, the Company was awarded 
the first ever Community Partner Award from the El Paso 
Neighborhood Association Coalition, in recognition of our 
continued partnership and community outreach efforts with the 
City of El Paso’s neighborhood associations. Additionally, we 
were also named a 2018 ENERGY STAR® Partner of the Year 
for our efforts in kilowatt-hour savings and increased education 
regarding energy efficiency. We will continue to look for ways 
to build on our customer experience and are committed to 
improving service to our customers.

As we continue to strengthen our Company and our partnerships  
with the community, we look forward to upholding our mission  
of providing safe, clean, reliable, and affordable energy to those 
we serve.

Mary E. Kipp 
President and 
Chief Executive Officer

Charles A. Yamarone 
Chairman of the Board 
of Directors

BOARD OF
DIRECTORS

Charles A. Yamarone 
Chairman of the Board 
El Paso Electric Company / 
Chief Corporate Governance and 
Compliance Officer 
Houlihan Lokey, a global investment bank 
Edward Escudero 
Vice Chairman of the Board 
El Paso Electric Company / 
President and Chief Executive Officer 
High Desert Capital, LLC, 
a finance company
Catherine A. Allen 
Founder, Chairman and 
Chief Executive Officer 
The Santa Fe Group, 
a strategic consulting company 

Paul M. Barbas 
Director, Dynegy Inc., an energy company / 
Retired President and Chief Executive 
Officer, DPL Inc. and its principal subsidiary, 
The Dayton Power and Light Company
James W. Cicconi 
Retired Senior Executive Vice President 
External and Legislative Affairs, 
AT&T Services, Inc.
Mary E. Kipp 
President and Chief Executive Officer 
El Paso Electric Company
Raymond Palacios, Jr. 
President, Bravo Cadillac, 
El Paso, Texas and Bravo Chevrolet Cadillac, 
Las Cruces, New Mexico, car dealerships
Eric B. Siegel 
Retired Limited Partner of Apollo Advisors, LP 
Senior Consultant and Special Advisor to 
the Chairman of the Milwaukee Brewers 
Baseball Club
Stephen N. Wertheimer 
Managing Director and Founding Partner, 
W Capital Partners, a private equity firm

OFFICERS

Mary E. Kipp 
President and Chief Executive Officer 

Elaina L. Ball 
Senior Vice President and 
Chief Administrative 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 
Development and Chief Compliance Officer
Adrian J. Rodriguez 
Senior Vice President, 
General Counsel and Assistant Secretary
R. Clay Doyle 
Vice President, 
Transmission and Distribution 

Russell G. Gibson 
Vice President, Controller
Eduardo Gutiérrez 
Vice President, Strategic Communications, 
Customer and Community Engagement 
David C. Hawkins 
Vice President, Generation, 
System Planning and Dispatch
Patrick V. Reinhart 
Vice President, Governmental Affairs
Victor F. Rueda 
Vice President, Human Resources
James A. Schichtl 
Vice President, Regulatory Affairs 
H. Wayne Soza 
Vice President, 
Compliance and Chief Risk Officer
Richard E. Turner 
Vice President, Business Development

 
 
 
 
 
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, 2018

OR

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  

    NO 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    YES  

    NO  

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  

   NO 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).    YES  

    NO  

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

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

Large accelerated filer
Non-accelerated filer

Accelerated filer
Smaller reporting company
Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for 

complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  

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

    NO  

As of June 30, 2018, the aggregate market value of the voting stock held by non-affiliates of the registrant was $2,196,858,522 (based 

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

As of January 31, 2019, there were 40,740,080 shares of the Company’s common stock outstanding.

Portions of the registrant’s definitive Proxy Statement for the 2019 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

A&G ................................................... Administrative and general
ABFUDC............................................ Allowance for Borrowed Funds Used During Construction
AEFUDC............................................ Allowance for Equity Funds Used During Construction
AFUDC .............................................. Allowance for Funds Used During Construction
ANPP Participation Agreement..........

Arizona  Nuclear  Power  Project  Participation Agreement  dated August  23,  1973,  as 
amended

AOCI .................................................. Accumulated Other Comprehensive Income
APS.....................................................
ARO ................................................... Asset Retirement Obligations
ASU....................................................
  Accounting Standards Update

  Arizona Public Service Company

  El Paso Electric Company

Company ............................................
CWIP.................................................. Construction Work In Progress
Copper ................................................ The Company's Copper Power Station
D.C. Circuit ........................................ U.S. Court of Appeals for the District of Columbia Circuit
DOE....................................................

  U.S. Department of Energy

  City of El Paso, Texas

El Paso................................................
EOC.................................................... The Company's Eastside Operations Center
EPA..................................................... U.S. Environmental Protection Agency
Exchange Act...................................... The Securities Exchange Act of 1934, as amended
FASB ..................................................

  Financial Accounting Standards Board

FERC..................................................

  Federal Energy Regulatory Commission

Fort Bliss ............................................

  Fort Bliss, the U.S. Army post next to El Paso, Texas

Four Corners....................................... Four Corners Generating Station
FPPCAC ............................................. New Mexico Fuel and Purchased Power Cost Adjustment Clause
GAAP ................................................. U.S. Generally Accepted Accounting Principles
GHG ................................................... Greenhouse Gas
HAFB ................................................. Holloman Air Force Base
kW ......................................................
kWh ....................................................

  Kilowatt(s)

  Kilowatt-hour(s)

Las Cruces ..........................................
MPS.................................................... The Company's Montana Power Station
MW.....................................................

  City of Las Cruces, New Mexico

  Megawatt(s)

  Megawatt-hour(s)

MWh...................................................
NAAQS .............................................. National Ambient Air Quality Standards
NAV.................................................... Net Asset Value
NDT.................................................... The Company's Palo Verde nuclear decommissioning trust funds
Net dependable generating capability

The maximum load net of plant operating requirements that a generating plant can supply 
under specified conditions for a given time interval, without exceeding approved limits 
of temperature and stress

Newman ............................................. The Company's Newman Power Station
NMPRC..............................................
NMPRC Final Order .......................... NMPRC Final Order in Case No. 15-00127-UT
NOL.................................................... Net Operating Losses

  New Mexico Public Regulation Commission

(i)

 
  
  
  
Abbreviations, Acronyms or Defined Terms
NOL carryforwards ............................ Net Operating Loss carryforwards
NRC....................................................
  Nuclear Regulatory Commission
OPEB Plan.......................................... The Company's other post-retirement benefits plan, including health care benefits for
retired employees and their eligible dependents and life insurance benefits for retired
employees only

Terms

O&M .................................................. Operations and maintenance
Palo Verde...........................................

  Palo Verde Generating Station

Palo Verde Participants.......................

Those utilities that share in power and energy entitlements, and bear certain allocated 
costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement

PCBs................................................... Pollution Control Bonds
PUCT..................................................
PURA ................................................. Public Utility Regulatory Act
RCF .................................................... The Company's Revolving Credit Facility
Retirement Plan .................................. The Company's Retirement Income Plan
RGEC .................................................

  Public Utility Commission of Texas

  Rio Grande Electric Cooperative

  Rio Grande Resources Trust II

RGRT..................................................
Rio Grande ......................................... The Company's Rio Grande Power Station
RPS..................................................... Renewable Portfolio Standard
SAB 118 ............................................. SEC Staff Accounting Bulletin No. 118
SEC..................................................... U.S. Securities and Exchange Commission
Securities Act...................................... The Securities Act of 1933, as amended
Standard Contract ............................... Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
TCJA................................................... The federal legislation commonly referred to as the Tax Cuts and Jobs Act of 2017
U.S...................................................... United States
White Sands........................................ White Sands Missile Range
2016 PUCT Final Order .....................

  PUCT Final Order in Docket No. 44941

2016 Study..........................................

2016 Palo Verde Decommissioning Study

2017 All Source RFP..........................

2017 All Source Request for Proposals for Electric Power Supply and Load Management 
Resources

2017 PUCT Final Order ..................... PUCT Final Order in Docket No. 46831
2019 Proxy Statement ........................ Proxy statement for the Company's 2019 Annual Meeting of Shareholders
2019 TCRF rate filing ........................ Transmission Cost Recovery Factor rate filing in PUCT Docket No. 49148

(ii)

  
  
 
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 
13 
21 
21 
21 
21 

PART II 
5  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ...
22 
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 .....................................................................................
45 
8  Financial Statements and Supplementary Data ............................................................................................................
47 
9  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ....................................... 113 
9A  Controls and Procedures .............................................................................................................................................. 113 
9B  Other Information ........................................................................................................................................................ 113 

PART III .................................................................................................................................................................   113 

 PART IV

 .................................................................................................................................................................   113 

(iii) 

 
 
 
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 ("Securities Act"), and Section 21E of 
the Securities Exchange Act of 1934, as amended ("Exchange Act"). Forward-looking statements often include words like "believe", 
"anticipate", "target", "project", "expect", "predict", "pro forma", "estimate", "intend", "will", "is designed to", "plan" and words 
of similar meaning, or are indicated by the El Paso Electric Company's (the "Company") discussion of strategies or trends. Forward-
looking statements describe the Company's future plans, objectives, expectations or goals. Although the Company believes that 
the expectations reflected in such forward-looking statements are reasonable, no assurances can be given that these expectations 
will prove to be correct. Such statements address future events and conditions and include, but are not limited to:

•

•

•

•

•

•

•

•

•

•

•

•

•

•

capital expenditures,

earnings,

liquidity and capital resources,

ratemaking/regulatory/compliance matters,

litigation,

accounting matters, including accounting for taxes and leases,

possible corporate restructurings, acquisitions and dispositions,

compliance with debt and other restrictive covenants,

interest rates and dividends,

environmental matters,

nuclear operations,

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

the availability and costs of new and /or emerging technologies, and

the overall economy of the Company's 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:

•

•

•

•

•

•

•

•

•

decisions and actions of the Company's regulators and the resulting impact on the Company's operations,
cost of capital, sales, and profitability,

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

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

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

reductions in output at generation plants operated by the Company,

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

the receipt of required approvals by regulators and other permits related to the Company’s construction
programs,

the Company's reliance on significant customers,

the credit worthiness of the Company's customers,

(iv)

•

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•

•

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•

•

•

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•

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•

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•

•

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 and battery storage,

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

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

the impact of changing cost escalation and other assumptions on the Company's nuclear decommissioning
liability for Palo Verde, as well as actual and assumed investment returns on assets in the Company's Palo
Verde nuclear decommissioning trust funds ("NDT"),

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

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

electric utility deregulation or re-regulation,

regulated and competitive markets,

ongoing municipal, state and federal activities,

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

political, legislative, judicial and regulatory developments,

homeland security considerations, including those associated with the United States ("U.S.")/Mexico border
region and the energy industry,

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

economic, commercial bank, financial and capital market conditions,

increases in cost of capital,

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

actions by credit rating agencies,

changes in accounting requirements and other accounting matters,

changing weather trends and the impact of severe weather conditions,

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

the impact of lawsuits filed against the Company,

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

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 U.S. Internal
Revenue Service or state taxing authorities,

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

the impact of international trade and tariff negotiations,

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

the effectiveness of the Company's risk management activities,

the Company's ability to successfully renegotiate its collective bargaining agreement,

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

(v)

•

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 Annual Report on Form 10-K under the headings "Risk Factors" and "Management’s Discussion and Analysis of 
Financial Condition and Results of Operations –Summary of Critical Accounting Policies and Estimates" and "Management’s 
Discussion and Analysis of Financial Condition and Results of Operations –Liquidity and Capital Resources." This Annual Report 
on Form 10-K should be read in its entirety. Management cautions against putting undue reliance on forward-looking statements 
or projecting any future results based on such statements or present or prior earnings levels. Any forward-looking statement speaks 
only as of the date such statement was made, and the Company is not obligated to update any forward-looking statement to reflect 
events or circumstances after the date on which such statement was made, except as required by applicable laws or regulations.

(vi)

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 capacity of approximately 2,085 megawatts ("MW"). For the 
year ended December 31, 2018, the Company’s energy sources consisted of approximately 44% nuclear fuel, 44% natural gas, 
12% purchased power and less than 1% generated by Company-owned solar photovoltaic panels. As of December 31, 2018, the 
Company had power purchase agreements for 107 MW from solar photovoltaic generation facilities and intends to expand its 
portfolio of renewable energy sources, particularly solar photovoltaic generation. See "Energy Sources – Purchased Power."

The Company serves approximately 425,000 residential, commercial, industrial, public authority and wholesale customers. 
The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing 
approximately 64% and 11%, respectively, of the Company’s retail revenues for the year ended December 31, 2018). 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 U.S. military installations, such as Fort Bliss in Texas and White 
Sands Missile Range ("White Sands") and Holloman Air Force Base ("HAFB") in New Mexico, an oil refinery, several medical 
centers, two large universities and a steel production facility.

The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone: 
915-543-5711). The  Company  was  incorporated  in Texas  in  1901. As  of  January 31,  2019,  the  Company  had  approximately
1,100 employees, 37% 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 U.S. Securities and Exchange Commission 
("SEC"). In addition, copies of this Annual Report on Form 10-K will be made available free of charge upon written request. The 
SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that 
file  electronically  with  the  SEC. The  address  of  that  site  is  www.sec.gov. The  information  on  the  Company's  website  is  not 
incorporated by reference into this Annual Report on Form 10-K.

As of December 31, 2018, the Company’s net dependable generating capability of approximately 2,085 MW consists of 

the following: 

Facilities

Station

Newman Power Station
Palo Verde
Rio Grande Power Station

Montana Power Station
(Units 1, 2, 3 and 4)
Copper Power Station

Renewables**
Total

Primary Fuel
Type
Natural Gas
Nuclear
Natural Gas

Natural Gas
Natural Gas

Solar

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

Company
Ownership
Interest

Location
El Paso, Texas
Wintersburg, Arizona

100%
15.8%
100% Sunland Park, New Mexico

100%
100%

100%

El Paso County, Texas
El Paso County, Texas
Culberson County and El
Paso County, Texas; Doña
Ana County and Otero
County, New Mexico

752
633
276

354
64

6
2,085

________________
* During summer peak period.
** Renewable nameplates are 8 MW with 70% contribution at time of peak.

1

 
Palo Verde

The Company owns an interest, along with six other utilities, in the three nuclear generating units and common facilities 
("Common Facilities") at Palo Verde. Arizona Public Service Company ("APS") serves as operating agent for Palo Verde, and 
under  the Arizona  Nuclear  Power  Project  Participation Agreement  dated August  23,  1973,  as  amended  ("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 U.S. Nuclear Regulatory Commission ("NRC"). The NRC issued full power operating licenses for Unit
1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and issued renewed operating licenses for
each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046
and November 2047, respectively.

• Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its
share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities,
through the term of their respective operating licenses. In 2017, the Palo Verde Participants approved the 2016
Palo Verde decommissioning study ("2016 Study"), which estimated that the Company must fund approximately
$432.8 million (stated in 2016 dollars) to cover its share of decommissioning costs. At December 31, 2018, the
Company's decommissioning trust fund had a balance of $276.9 million. Although the 2016 Study was based
on the latest available information, there can be no assurance that decommissioning cost estimates will not
increase in the future or that regulatory requirements will not change.

•

Spent Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987, the U.S.
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 ("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. Pursuant
to the terms of the August 18, 2014 settlement agreement, and as amended with the DOE, APS files annual
claims for the period July 1 of the then-previous year to June 30 of the then-current year on behalf of itself and
those utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo
Verde  based  upon  the ANPP  Participation Agreement  dated August  23,  1973. The  settlement  agreement,  as
amended, provides APS with a method for submitting claims and receiving recovery for costs incurred through
December 31, 2016, which has been extended to December 31, 2019. The Company's share of costs recovered
in 2018, 2017, and 2016, respectively are presented below (in thousands):

Costs Recovery Period

Amount Refunded

Amount Credited to
Customers through
Fuel Adjustment
Clauses

Period Credited to
Customers

July 2016 - June 2017

$

July 2015 - June 2016

July 2014 - June 2015

$

1,413

1,779

1,884

1,121

1,432

1,581

March 2018

March 2017

March 2016

On October 31, 2018, APS filed a $10.2 million claim for the period July 1, 2017 through June 30, 2018. The 
Company's share of this claim is approximately $1.6 million. This claim is pending DOE review. The majority 
of the reimbursement received by the Company is expected to be credited to customers through the applicable 
fuel adjustment clauses.

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

2

District of Columbia Circuit ("D.C. Circuit"). In August 2013, the D.C. Circuit ordered the NRC to resume its 
review of the application with available appropriated funds.

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

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

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

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

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

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

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

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

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

3

fuel adjustment clauses. In June 2012, the D.C. Circuit held that the DOE failed to conduct a sufficient fee 
analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the Secretary 
of the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, 
upon completion of the DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. 
On November 19, 2013, the D.C. Circuit ordered the Secretary of the DOE 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 of the DOE notified Congress 
of his intention to suspend collection of the one-mill fee, subject to Congress’ disapproval and on May 16, 2014, 
the DOE notified all commercial nuclear power plant operators, effective May 16, 2014, the one-mill fee was 
suspended. Electricity generated at Palo Verde and sold on or after May 16, 2014 is no longer subjected to the 
one-mill fee.

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

The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements.
Palo Verde has met the NRC's imposed deadlines for the installation of equipment to address these requirements.
Palo  Verde  has  spent  approximately  $125.4  million  (the  Company's  share  is  $19.8  million)  on  capital
enhancements related to these requirements as of December 31, 2018.

• 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  $62.1  million,  with  an  annual  payment  limitation  of
approximately $9.7 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 $2.3 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 Company owns the Newman Power Station ("Newman"), which 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  owns  the  Rio  Grande  Power  Station  ("Rio  Grande"),  which  consists  of  two  conventional  steam-electric 
generating units and one aeroderivative unit that operates on natural gas. Rio Grande Unit 6 with net capacity of 42.5 MW, was 
initially placed in inactive reserve status in 2015, and has been activated as needed.  

The Company owns the Montana Power Station ("MPS"), which consists of four aeroderivative generating units that operate 

on natural gas. The units can also operate on fuel oil.

The Company owns the Copper Power Station ("Copper"), which consists of a natural gas combustion turbine used primarily 

to meet peak demand.

Prior to July 6, 2016, the Company owned a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners"). 
The Company shared power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) 
and the other Four Corners participants. On July 6, 2016, the Company sold its interests in Four Corners for $32.0 million to 4C 
Acquisition, LLC, an affiliate of APS ("APS's affiliate"), and Pinnacle West Capital Corporation ("Pinnacle West"), the parent 
company of APS and APS's affiliate. No significant gain or loss was recorded for this sale. APS's affiliate assumed responsibility 
4

for all Four Corners capital expenditures made after July 6, 2016, which assumption is guaranteed by Pinnacle West. In addition, 
APS's affiliate will indemnify the Company against certain liabilities and costs related to the future operation of Four Corners, 
which indemnification is guaranteed by Pinnacle West. See Part II, Item 8, Financial Statements and Supplementary Data, Note 
D and Note F of Notes to Financial Statements for further discussions. 

Solar Photovoltaic Facilities

The Company’s Texas Community solar facility, a 3 MW utility-scale solar plant located at MPS, and the El Paso Electric 
Holloman Atlas Solar Array, a 5 MW utility-scale solar plant located on HAFB, began commercial operations on May 31, 2017, 
and October 18, 2018, respectively. The Company also owns six other solar photovoltaic facilities with a total capacity of 0.2 MW.

Transmission and Distribution Lines and Agreements

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

In addition to the transmission and distribution lines within our service territory, the Company's transmission network and 

associated substations include the following:

Line
Springerville-Macho Springs-Luna-Diablo Line (1)
West Mesa-Arroyo Line (2)
Greenlee-Hidalgo-Luna-Newman Line (3)

Length (miles)
310
202

Greenlee-Hidalgo
Hidalgo-Luna
Luna-Newman
Eddy County-AMRAD Line (4)
Palo Verde Transmission

Palo Verde-Westwing (5)
Palo Verde-Jojoba-Kyrene (6)

60
50
86
125

45
75

Voltage (kV)

Company
Ownership
Interest

345
345

345
345
345
345

500
500

100.0%
100.0%

40.0%
57.2%
100.0%
66.7%

18.7%
18.7%

____________________
(1) Runs from Tucson Electric Power Company's ("TEP") Springerville Generating Plant near Springerville, Arizona,

to the Company's Diablo Substation near Sunland Park, New Mexico.

(2) Runs from Public Service Company of New Mexico's ("PNM") West Mesa Substation near Albuquerque, New

Mexico, to the Company's Arroyo Substation near Las Cruces, New Mexico.

(3) Runs from TEP's Greenlee Substation near Duncan, Arizona to Newman.
(4) Runs from the Company's and PNM's high voltage direct current terminal at the Eddy County Substation near

Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico.

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

Phoenix near Peoria, Arizona.

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

Tempe, Arizona.

5

Environmental Matters

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

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

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, particulate matter and nitrogen oxides.

National Ambient Air Quality Standards ("NAAQS"). Under the CAA, the U.S Environmental Protection Agency ("EPA") 
sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including particulate matter, 
nitrogen oxide, carbon monoxide, ozone and sulfur dioxide. On October 1, 2015, the EPA released a final rule tightening the 
primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion ("ppb") to 70 ppb. 
The EPA published the Final Rule on June 4, 2018, designating El Paso County, Texas, as "attainment/unclassifiable" under the 
2015 ozone NAAQS and designating a section of southern Doña Ana County, New Mexico, as "nonattainment." In August, several 
petitions for review of the Final Rule were filed in the D.C. Circuit. One of these petitions, filed by the City of Sunland Park, 
New Mexico, specifically challenges the "attainment/unclassifiable" designation of El Paso County, Texas. The Company and 
other intervenors filed and were granted motions to intervene in the challenges to EPA's 2015 ozone NAAQS designations. A 
briefing schedule extending through July 2019 has been established for the case.

States, including New Mexico, that contain any areas designated as nonattainment are required to complete development of 
implementation plans in the 2020-2021 timeframe. Most nonattainment areas are expected to have until 2020 or 2023 to meet the 
primary (health) standard, with the exact attainment date varying based on the ozone level in the area. The Company continues to 
evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional 
equipment to control emissions at its facilities, the NAAQS, individually or in the aggregate, could have a material impact on its 
operations and financial results.

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

Climate Change. There has been a wide-ranging policy debate, at the local, state, national and international levels, regarding 
the impact of GHG and possible means for their regulation. Efforts continue to be made in the international community toward 
the adoption of international treaties or protocols that would address global climate change issues. In April 2016, the United States 
signed the Paris Agreement, which requires countries to review and "represent a progression" in their intended nationally determined 
contributions, which set GHG emission reduction goals, every five years beginning in 2020. In August 2017, the United States 
formally  documented  to  the  United  Nations  its  intent  to  withdraw  from  the  Paris Agreement. The  earliest  possible  effective 
withdrawal date from the Paris Agreement is November 2020. At the state level, several states have already adopted measures 
requiring GHG emissions to be reduced within state boundaries. For example, the governor of New Mexico signed an executive 
order in January 2019 that supports the Paris Agreement and includes a goal of reducing statewide GHG emissions by at least 45% 
by 2030. The executive order also creates a Climate Change Task Force to evaluate and develop regulatory strategies to reach the 
45% reduction goal. Although the Company cannot currently determine the effect of potential regulatory strategies that may be 

6

suggested by the New Mexico Climate Change Task Force, if implemented, they could be material to the Company's business, 
reputation, financial condition or results of operations. 

The  federal  government  has  considered,  proposed  and/or  finalized  legislation  or  regulations  limiting  GHG  emissions, 
including carbon dioxide. In particular, the U.S. Congress has considered legislation to restrict or regulate GHG emissions. In 
October 2015, the EPA published a rule establishing guidelines for states to regulate carbon dioxide emissions from existing power 
plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. On August 31, 2018, the EPA published 
a proposal to replace the CPP called the Affordable Clean Energy ("ACE") rule. The ACE rule has not yet been finalized. At this 
time the Company cannot determine the impact that the CPP, the ACE rule, and related proposals and legal challenges may have 
on our financial position, results of operations or cash flows. 

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

Climate change also has potential physical effects that could be relevant to the Company's business. 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 significant 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 not possible to meaningfully quantify 
the costs of these potential impacts at present.

Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice, on behalf of the EPA, and 
APS have been engaged in substantive settlement negotiations in an effort to resolve certain pending matters. The allegations 
being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary 
under the CAA to reduce sulfur dioxide, nitrogen oxides, and particulate matter, and that APS failed to obtain an operating permit 
under Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. 
District Court for the District of New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On 
August 17, 2015, the U.S. District Court 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, 2018, the Company has accrued its remaining unpaid share of 
approximately $0.2 million related to this matter. 

7

Construction Program 

Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating 
the transmission and distribution systems, the cost of capital improvements and replacements at Palo Verde and other generating 
facilities, and other property and equipment. Studies indicate that the Company will need additional power generation resources 
to meet increasing load requirements on its system and to replace retiring plants. After evaluation of the competitive 2017 All 
Source Request for Proposals for Electric Power Supply and Load Management Resources (“2017 All Source RFP”), the winning 
bids include the construction of a 226 MW natural gas combustion turbine generating unit at Newman in El Paso with an anticipated 
operational date in 2023. The costs of the new generating unit are included in the table below. The winning bids also included 
purchased power agreements for 200 MW of utility scale solar resources and 100 MW of battery storage, which are not included 
in the construction program. The selected proposals are subject to the execution of contracts following negotiations with the 
winning bidders, obtaining the applicable environmental and construction related permits, and obtaining necessary approvals by 
the Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC").

The Company’s estimated cash construction costs for 2019 through 2023 are approximately $1.3 billion. Actual costs may 
vary from the construction program estimates shown. Such estimates are under continuous review and subject to ongoing adjustment 
and are updated periodically to reflect changed conditions.

By Year (1)(2)(3)
(estimates in millions)

2019................................................... $
2020...................................................
2021...................................................
2022...................................................
2023...................................................

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

249
224
266
278
279
1,296

By Function
(estimates in millions)

Production (1)(2) ........................ $
Transmission...............................
Distribution (3) ...........................
General........................................

450
167
518
161

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

1,296

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

a.

$185 million for new generating capacity, including:

i.

ii.

$143 million of construction costs from 2019 through 2023 for a 226 MW combustion turbine
generating unit at Newman with an anticipated operational date in 2023 as a result of the 2017
All Source RFP.
$42 million of initial construction costs from 2019 through 2023 for a 320 MW combined cycle
generating unit to be completed in 2027.

b.

$265 million of other generation costs, including $185 million for Palo Verde.

(3) Estimated distribution costs include:

a.

$85 million of initial project costs for Advanced Metering Infrastructure ("AMI"), including deployment
of the back-office systems and meters. Legislative proposals regarding the clarification of the regulatory
process to implement AMI are anticipated during the Texas legislative session that convened in January
2019. With legislative clarification, the Company would then have the opportunity to request regulatory
approval for the deployment of AMI.

8

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 of the Company.

Years Ended December 31,

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

2018

2017
(percentage of total kWh energy mix)

2016

44%
44%
—%
12%
100%

49%
36%
—%
15%
100%

49%
34%
2%
15%
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 PUCT and the 
NMPRC. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further 
discussion on Texas 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 through 2025 and 15% of its requirements through 2028. The participants have contracted for 100% of 
Palo Verde's requirement for conversion services through 2025 and 40% of its requirements through 2028. The participants have 
also contracted for 100% of Palo Verde's requirement for enrichment services through 2021 and 90% of its requirement for 2022, 
and 80% for 2023 through 2026 and all of Palo Verde's requirement for fuel assembly fabrication services through 2027.

Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust II 
("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. As of December 31, 2018, RGRT 
has $110 million aggregate principal amount of senior notes due 2020 and 2025. On June 28, 2018, RGRT completed the sale of 
$65 million aggregate principal amount of senior notes due August 15, 2025. The Company guarantees the payment of principal 
and interest on the RGRT senior notes. The proceeds from the sale of the RGRT senior notes were used by RGRT to repay amounts 
borrowed under the then-existing revolving credit facility and enable future nuclear fuel financing requirements of RGRT to be 
met with a combination of the senior notes and amounts borrowed under the Company's Revolving Credit Facility ("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. Through March 2018, the Company’s 
natural gas requirements at Newman, Rio Grande and MPS were met with short-term, medium-term and long-term natural gas 
purchases from various suppliers; thereafter, there were only short-term and medium term natural gas purchases, and this practice 
is expected to continue in 2019. 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.

9

 
Natural gas for Newman and Copper was also delivered pursuant to a long-term intrastate natural gas contract for firm 
transportation that became effective October 1, 2009 and continued through March 31, 2018. Beginning April 1, 2018, intrastate 
natural gas reservation and storage for Newman and Copper has been provided through new contracts with ONEOK WesTex 
Transmission, LLC and ONEOK Texas Gas Storage, LLC, respectively, that continue through March 31, 2028. It is anticipated 
that deliveries of intrastate natural gas to MPS may begin in the first quarter of 2019. Under this new contract, intrastate gas supply 
will be sourced in the same manner as interstate gas through a variety of medium and short-term purchase contracts.

Purchased Power

To supplement its own generation and operating reserve requirements, and to meet its Renewable Portfolio Standard ("RPS") 
requirements, 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 RPS requirements.

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

The Company has entered into several power purchase agreements to help meet its RPS requirements. Specifically, the 
Company has a 25-year power purchase 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 I, LLC to provide for additional or replacement photovoltaic modules. The 
Company also entered into a 20-year contract with Solar Roadrunner, LLC, a subsidiary of Global Infrastructure Partners, (formerly 
known as NRG Solar Roadrunner LLC) 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 power purchase agreements 
to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunE EPE1, LLC (10 
MW) and SunE EPE2, LLC (12 MW), which began commercial operation in June 2012 and May 2012, respectively. In September 
2017, Longroad Solar Portfolio Holdings, LLC purchased SunE EPE1, LLC, and in October 2017, Silicon Ranch Corporation 
purchased SunE EPE2, LLC with the Company's consent per the terms of both power purchase agreements. 

Furthermore, the Company has a 20-year power purchase 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 power purchase agreement with Newman 
Solar LLC to purchase the total output, which is approximately 10 MW, from a solar photovoltaic generation plant on land subleased 
from the Company in proximity to Newman. This solar project began commercial operation in December 2014.

Other purchases of shorter duration were made during 2018 to supplement the Company's generation resources during planned 

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

The Company recently concluded and announced its selection of resources from its 2017 All Source RFP. In addition to 
conventional  natural  gas  generation,  the  Company  will  be  initiating  contract  negotiations  during  2019  for  power  purchase 
agreements  from  both  solar  and  battery  storage  resources.  Furthermore,  the  Company  will  pursue  negotiations  for  possible 
additional solar and wind purchase power if there are potential energy cost savings.

10

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 - full requirement customer .................................
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.............................................................................................
Wheeling revenues.........................................................................................
Energy efficiency cost recovery.....................................................................
Miscellaneous ................................................................................................
Total revenues from customers .....................................................
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,
2017

2016

2018

$

$

297,597
194,341
34,920
95,460
622,318

2,780
625,098

156,493
(4,736)
—
151,757
86,418
19,026
8,888
8,188
899,375
4,228
903,603

376,651
42,141
48
6,170
425,010
7,988

$

$

287,884
198,799
38,403
97,890
622,976

2,730
625,706

218,380
(17,133)
—
201,247
58,986
18,114
—
8,229
912,282
4,515
916,797

370,054
42,291
48
5,500
417,893
7,671

278,774
194,942
39,070
96,881
609,667

2,407
612,074

148,397
14,893
33,279
196,569
45,702
21,966
—
7,034
883,345
3,591
886,936

363,987
41,741
49
5,285
411,062
7,748

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

9,943,721
1,355,309
11,299,030

8,950,875
1,540,841
10,491,716

8,820,006
1,552,251
10,372,257

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 - full requirement customer ...........................................
Off-system sales......................................................................................
Total wholesale..............................................................................
Total energy sales...................................................................
Losses and Company use ...............................................................................
Total .......................................................................................

2,988,695
2,431,920
1,050,834
1,563,227
8,034,676

58,991
2,687,961
2,746,952
10,781,628
517,402
11,299,030

2,823,260
2,410,710
1,045,319
1,564,670
7,843,959

62,887
2,042,884
2,105,771
9,949,730
541,986
10,491,716

2,805,789
2,403,447
1,030,745
1,572,510
7,812,491

62,086
1,927,508
1,989,594
9,802,085
570,172
10,372,257

Native system:

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

1,929,000
2,085,000

1,935,000
2,082,000

1,892,000
2,080,000

Total system:

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

2,006,000
2,085,000

1,982,000
2,082,000

2,027,000
2,080,000

___________________________
(1)
(2)

The number of retail customers presented is based on the number of service locations.
Includes spot sales and net losses of 77,000 kilowatts ("kW"), 47,000 kW and 135,000 kW for 2018, 2017 and 2016, respectively.

11

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 - full 
requirement  customer)  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. See Part II, Item 8, Financial Statements and 
Supplementary Data, Note D of Notes to Financial Statements for further discussion on Regulatory Matters.

Power Sales Contracts

The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2018.

Franchises and Significant Customers

Franchises

The Company operates under franchise agreements with several cities in its service territory, including one with El Paso, 
Texas, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve 
its customers within El Paso. Pursuant to the El Paso franchise agreement, the Company pays to the City of El Paso, on a quarterly 
basis, a fee equal to 5.00% 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 that amount has since been adjusted by two amendments. 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. The 2018 amendment, approved on March 20, 2018, and applicable to bills issued on or after October 1, 2018, increased 
the dedicated incremental fee by 1.00% of gross revenues and extended the term of the franchise agreement by 30 years. 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, 2060.

The Company does not have a written franchise agreement with Las Cruces, New Mexico, the second largest city in its 
service territory. The Company utilizes public rights-of-way necessary to service its customers within Las Cruces under an implied 
franchise pursuant to state law 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. 

The Company also maintains franchise agreements with other municipalities, and applicable counties, within its service 

territories. 

Military Installations

The Company serves HAFB, White Sands and Fort Bliss. These military installations represent approximately 2.6% of the 
Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss under which Fort Bliss takes 
retail electric service from the Company under the applicable Texas tariffs. The Company serves White Sands under the applicable 
New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under which the Company provides retail electric 
service and limited wheeling services to HAFB under the applicable New Mexico tariffs. As stated in the contract, HAFB will 
purchase the full output of a Company-owned 5 MW solar facility upon its completed construction, which occurred on October 
18, 2018. HAFB's other power requirements are provided under the applicable New Mexico tariffs with limited wheeling services 
under the contract.

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. 

12

Item 1A.  Risk Factors 

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

Our Revenues and Profitability Depend Upon Regulated Rates

Our rates are governed by Texas, New Mexico and federal laws and regulations, with our retail rates subject to regulation 
by incorporated municipalities in Texas, the PUCT, the NMPRC and our wholesale rates subject to regulation by the FERC. There 
can be no assurance that the laws and regulations or the application thereof in our different jurisdictions will be similar or consistent, 
which could lead to different treatment of certain matters by our regulators in different jurisdictions. The PUCT Final Order in 
Docket No. 46831 ("2017 PUCT Final Order") established our current retail base rates in Texas, effective July 18, 2017. In addition, 
the NMPRC Final Order in Case No. 15-00127-UT ("NMPRC Final Order") established rates in New Mexico that became effective 
in July 2016.

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

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

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

We announced the results of the 2017 All Source RFP on December 26, 2018, that includes a diverse generation mix. The 
selected proposals are subject to the execution of contracts following negotiations with the winning bidders, obtaining the applicable 
environmental and construction related permits and obtaining necessary approvals by the PUCT and the NMPRC. 

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

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

The global credit and equity markets and the overall economy can be extremely volatile which could have a number of 
adverse effects on our operations, funding obligations 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 
13

credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in stock 
market performance may reduce the value of our financial assets and decommissioning trust investments and negatively impact 
our results of operations. Similarly, inflationary increases will increase our future decommission obligations. Such market results 
may also increase our funding obligations for our pension plans, other post-retirement benefit plans and the NDT. 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,  an  economic  downturn  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. The credit markets 
and overall economy (including inflationary increases) may also adversely impact our ability to arrange future financings on 
acceptable terms and therefore our ability to refinance our existing indebtedness could be limited. Furthermore, the credit markets 
and overall economy may also adversely impact the financial health of our suppliers. If that were to occur, our access to and prices 
for inventory, supplies and capital equipment could be adversely affected. Our power trading counterparties could also be adversely 
impacted by the market and economic conditions which could result in reduced wholesale power sales or increased counterparty 
credit risk.

Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. Partial government 
shutdowns, such as occurred in 2013 and the end of 2018 and the beginning of 2019, can impact both sales and timely receivables 
from public authorities, commercial, industrial and residential customers. The occurrence of any of these events could have a 
material adverse effect on our results of operations, financial condition and cash flows.

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 U.S., subjects us 
to a number of risks. A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses 
is attributable to Palo Verde. Our interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. 
Palo Verde represents approximately 30% of our available net generating capacity and provided approximately 44% of our energy 
requirements for the twelve months ended December 31, 2018. Palo Verde comprises approximately 24% of our total net plant-
in-service and Palo Verde expenses comprise a significant portion of O&M 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 90.2% and 93.8% in the twelve months ended December 31, 2018 and 2017, respectively.

We participate in Palo Verde with one or more parties who may not have the same goals, strategies, priorities or resources 
as we do and may compete with us. Furthermore, regulatory compliance issues and financial restraints could cause these parties 
to make decisions that could potentially be adverse to us. Additionally, if one or more of the participants defaults in performance 
of its obligations under the ANPP Participation Agreement, the non-defaulting participants must bear all operating, maintenance, 
and other costs otherwise payable by the defaulting participant (and will receive the generation share of the defaulting participant) 
in the ratio of their respective share to the total shares of all non-defaulting participants.

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

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

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

14

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

Adverse Changes in Our Credit Ratings Could Negatively Affect Our Access to the Capital Markets and our Cost of 
Borrowed Funds

Access to the capital markets is important to our ability to operate our business and complete our capital projects. Credit 
rating agencies evaluate our credit ratings on a periodic basis and when certain events occur. These ratings are premised on financial 
ratios and performance, our regulatory environment and rate mechanisms, resource risks and power supply costs, and other factors. 
A ratings downgrade could increase fees on the RCF thereby increasing the cost of funding day-to-day working capital requirements, 
and could also result in higher interest rates on future long-term debt. In addition, any ratings downgrade or placement of our 
credit ratings on negative watch could have an adverse impact on the price of our common stock. If access to capital were to 
become  significantly  constrained  or  costs  of  capital  increased  significantly  due  to  lowered  credit  ratings,  prevailing  industry 
conditions,  regulatory  constraints,  the  volatility  of  the  capital  markets  or  other  factors,  our  financial  condition  and  results  of 
operations could be adversely affected.

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

Our service territory is in west Texas and southern New Mexico and is particularly susceptible to dry and hot temperatures 
in the summer months. These seasonal weather patterns result in temperatures that can lead to daytime highs exceeding 100 degrees 
Fahrenheit for extended periods during the summer when we typically experience peak kWh sales at higher summer rates. Milder 
temperatures during this period will occur occasionally and result in less kWh sales which will adversely affect our results of 
operations. From time to time, we experience extreme weather conditions, including high winds (usually in the spring months but 
can occur during other months), that may result in unplanned outages. Under such conditions, we may incur additional costs to 
repair and, or, to replace equipment. Depending upon the length and extent of the damage, we may also incur additional purchase 
power costs. Fallen power lines and poles can cause severe damage to customer property and subject us to claims, all of which 
could have a material adverse effect on our results of operations and cash flows.

Equipment Failures and Other External Factors Can Adversely Affect Our Results

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

15

future at competitive market rates. In the event future insurance costs and/or deductible amounts increase, our financial condition, 
operating results and cash flows could be materially adversely affected. 

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

As a result of changes in federal law, our wholesale and large retail customers have access to, in varying degrees, alternative 
sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate 
our  transmission  and  distribution  functions,  which  would  remain  regulated,  from  our  power  generation  and  energy  services 
businesses,  which  would  operate  in  a  competitive  market,  in  the  future.  In  2004,  the  PUCT  approved  a  rule  delaying  retail 
competition in our Texas service territory. This rule was codified in the Texas Public Utility Regulatory Act ("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  NAAQS.  If  these 
regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our 
financial results.

Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for
Electricity or Availability of Resources, and Could Result in Increased Compliance Costs

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

In October 2015, the EPA published a rule establishing guidelines for states to regulate carbon dioxide emissions from 
existing power plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. On August 31, 2018, 
the EPA published a proposal to replace the CPP called the Affordable Clean Energy ("ACE") rule. The ACE rule has not yet been 
finalized. The potential impact of these GHG rules (if and when finalized) on us is unknown at this time, but they could result in 
significant costs, limitations on operating hours, and/or changes in construction schedules for future generating units.

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

16

Adverse Regulatory Decisions or Changes in Applicable Regulations or Laws Could Have a Material Adverse Effect on 
Our Business or Result in Significant Additional Costs

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

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

In addition, our service territory borders with Mexico and as such businesses in our service territory rely heavily on commerce 
with businesses in Mexico. Changes in regulations or enforcement restricting such commerce activities could reduce our customer 
growth rate and materially adversely affect our results of operations, financial condition and cash flows.

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 ("TCJA") was signed into law, enacting significant changes to 
the Internal Revenue Code of 1986 (as amended, the "IRC”). Key provisions impacting the Company include a reduction in the 
federal  corporate  income  tax  rate  from  35%  to  21%  effective  January  1,  2018,  the  discontinuation  of  bonus  depreciation  for 
regulated public utilities for assets acquired and placed into service after December 31, 2017, elimination of corporate alternative 
minimum tax provisions, limitations on the utilization of net operating losses ("NOL") arising after December 31, 2017 to 80% 
of taxable income with no carryback but with an indefinite carryforward, and additional limitations on the deductibility of executive 
compensation. We continue to evaluate the impact of the TCJA as regulations related to the TCJA are finalized to determine whether 
any of these changes could have a material adverse effect on our results of operations, financial condition, and cash flows.

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.

As domestic and global cyber threats are on-going and increasing in sophistication, magnitude and frequency, our critical 
energy infrastructure may be targets of terrorist activities or otherwise could disrupt our business operations. Any such disruptions 
could result in significant costs to repair damaged facilities and implement increased security measures, which could have a material 
adverse effect on our results of operations, financial condition and/or cash flows.

17

We May Incur Additional Capital and Operating Costs in Connection with the Physical Security and Cyber Security of 
New Technologies

We operate in a highly regulated industry that requires the continued operation and development of sophisticated information 
technology systems and network infrastructure. The introduction of new technology and the emergence of new industry standards 
and  technological  hurdles  can  create  unanticipated  difficulties,  including  failures  or  inadequacy  of  equipment  or  software, 
difficulties in integrating the various components of the equipment, changes in technology, cybersecurity issues and factors outside 
our  control,  which  could  negatively  affect  our  results  of  operations  and  financial  condition. As  we  continue  to  develop  new 
technology to keep up with the demands of the industry and the needs of our customers, we may be required to expend significant 
capital and other resources to protect against security breaches or to alleviate problems caused by security breaches.

Failure to Maintain the Security of Personally Identifiable Information Could Adversely Affect Us

In connection with our business we and our vendors, suppliers and contractors collect and retain personally identifiable 
information (e.g., information of our customers, shareholders, suppliers and employees), and there is an expectation that we and 
such third parties will adequately protect that information. The U.S. regulatory environment surrounding information security and 
privacy is increasingly demanding. A significant theft, loss or fraudulent use of the personally identifiable information we maintain 
or failure by our vendors, suppliers and contractors to use or maintain such information in accordance with contractual provisions 
could adversely impact our reputation and could result in significant costs, fines, litigation and loss of reputation.

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

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

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

Inflation Could Adversely Affect Our Financial Results 

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

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

We are a fully vertically integrated electric utility company whose only business is the generation, transmission and distribution 
of electricity to customers in an area of approximately 10,000 square miles in west Texas and southern New Mexico. Approximately 
87% of revenues are directly related to the retail sales of electric power to approximately 425,000 residential, commercial and 
public authority customers. As such, risks uniquely associated with the utility industry such as changes in utility legislation and 
regulations, weather patterns in the region and economic conditions will have a greater effect on our overall operating results than 
otherwise if our operations were more diversified into other lines of business and in a broader geographical area.

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

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

18

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

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

including:

•

•

•

•

•

•

•

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

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

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

labor disputes;

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

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

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

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

Our Success Depends on the Availability of the Services of a Qualified Workforce and Our Ability to Attract and 

Retain Qualified Personnel and Senior Management

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

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

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

Our Ability to Accurately Report Our Financial Results or Prevent Fraud May Be Adversely Affected if We Fail to 

Maintain an Effective System of Internal Controls

Effective internal controls are necessary for us to provide reliable financial reports, effectively prevent fraud and operate 
successfully as a public company. If our efforts to maintain an effective system of internal controls are not successful, we are 
unable to maintain adequate controls over our financial reporting and processes in the future or we are unable to comply with our 
obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed, or we may fail to meet 

19

our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial 
information, which would likely have a negative effect on the trading price of our common stock and other securities.

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

Financial Results

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

We Are Subject to Costs and Other Effects of Legal and Regulatory Proceedings, Disputes and Claims

From time to time in the normal course of business, we are subject to various lawsuits, audits, regulatory proceedings, 
disputes,  and  claims  that  could  result  in  adverse  judgments  or  settlements,  fines,  penalties,  injunctions,  or  other  adverse 
consequences. These matters are subject to a number of uncertainties, and management is often unable to predict the outcome of 
such matters; resulting liabilities could exceed amounts currently reserved or insured against with respect to such matter. The legal 
costs and final resolution of matters in which we are involved could have a reputational impact and/or a short- or long-term negative 
effect on our results of operations, financial condition and/or cash flows. Similarly, the terms of resolution could require us to 
change our operational practices and procedures, which could also have a material adverse effect on our results of operations, 
financial condition and/or cash flows.

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

Our Articles of Incorporation and Bylaws contain provisions that may make acquiring control of the Company difficult and 

could preclude our shareholders from receiving a change of control premium, including: 

•

•

•

•

•

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

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

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

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

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

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

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

20

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 and distribution lines are located either on company-owned land, private rights-of-way, easements or 
on streets or highways by public consent.

The Company owns an executive and administrative office building and various operations centers in El Paso County, Texas, 
and Doña Ana County, New Mexico. The Company leases land in El Paso, Texas, adjacent to Newman under a lease that expires 
in June 2033, subject to a renewal option of 25 years. The Company has several other leases for office and parking facilities that 
expire within the next five years.

Item 3. 

Legal Proceedings

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

See Part I, Item 1, "Business – Environmental Matters" and Part II, Item 8, "Financial Statements and Supplementary Data, 
Note D, Note M and Note L of Notes to Financial Statements" for further 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.

21

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." 

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, 
2013 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

As of December 31,

2013

2014

2015

2016

2017

2018

100
100
100

118
129
104

117
124
98

144
145
106

176
163
123

164
168
109

22

 
As of January 31, 2019, there were 2,176 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 $57.5 million in cash dividends 
during the twelve months ended December 31, 2018. On January 31, 2019, the Board of Directors declared a quarterly cash 
dividend of $0.36 per share payable on March 29, 2019, to shareholders of record as of the close of business on March 15, 
2019. Typically, the Board of Directors reviews the Company’s dividend policy annually in the second quarter of each year. 
Declaration and payment of dividends is subject to compliance with certain financial tests under Texas law. Since 1999, the 
Company has also returned cash to shareholders through a stock repurchase program pursuant to which the Company has 
bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s 
program, purchases can be made at open market prices or in private transactions. 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 ("2011 Plan"). No shares of 
common stock were repurchased during the twelve months ended December 31, 2018, 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, 2018
November 1 to November 30, 2018
December 1 to December 31, 2018

Total
Number
of Shares
Purchased (a)

Average Price
Paid per Share
(Including
Commissions)
—
—
50.13

— $
—
12,205

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

_____________________
(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.

On January 30, 2019, the Company submitted an application with both the NMPRC and the FERC seeking approval to
issue shares of common stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more 
transactions. In order to align the number of shares of common stock held as treasury stock by the Company with various 
regulatory  applications,  filings  and  orders,  on  January  31,  2019,  the  Board  of  Directors  of  the  Company  approved  the 
cancellation of 1.4 million shares of Common Stock held as treasury shares by the Company effective upon the later of approval 
by the FERC of the accounting treatment of the cancellation and March 31, 2019. 

For Equity Compensation Plan Information see Part III, Item 12, "Security Ownership of Certain Beneficial Owners 

and Management and Related Stockholder Matters."

23

Item 6. 

 Selected Financial Data

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

Years Ended December 31,

Operating revenue ...................................................... $
Operating income (b) ................................................. $
Net income ................................................................. $
Basic earnings per share:

903,603

172,229

84,315

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

2.07
Weighted average number of shares outstanding....... 40,521,364
Diluted earnings per share:

2018 (a)

2017

$

$

$

$

916,797

190,059

98,261

2.42

$

$

$

$

2016

886,936

187,911

96,768

2.39

2015

849,869

146,191

81,918

2.03

$

$

$

$

2014

917,525

151,163

91,428

2.27

$

$

$

$

40,414,556

40,350,688

40,274,986

40,190,991

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

2.07

$

2.42

$

2.39

$

2.03

$

2.27

Weighted average number of shares and dilutive

 potential shares outstanding ............................... 40,642,640

40,535,191

40,408,033

40,308,562

40,211,717

Dividends declared per share of common stock......... $
Cash additions to utility property, plant and
equipment (c).............................................................. $
240,021
Total assets ................................................................. $ 3,628,502
Long-term debt, net of current portion....................... $ 1,285,980
Common stock equity................................................. $ 1,164,103

1.415

$

$

1.315

199,896

$

$

1.225

229,722

$

$

1.165

281,458

$

$

1.105

277,078

$ 3,484,363

$ 3,376,278

$ 3,200,607

$ 3,033,400

$ 1,195,988

$ 1,195,513

$ 1,122,660

$ 1,122,235

$ 1,142,165

$ 1,074,396

$ 1,016,538

$

984,254

________________
(a) Effective January 1, 2018, the Company implemented Accounting Standards Update ("ASU") 2016-01, Financial Instruments
- Overall: Recognition and Measurement of Financial Assets and Liabilities. As required by the new standard, changes in
the fair values of the Company's equity investments are recognized in earnings, whereas prior to 2018, such changes were
recognized in accumulated other comprehensive income ("AOCI").

(b) The Company implemented ASU 2017-07, Compensation - Retirement Benefits (Topic 715), in the first quarter of 2018,

and as required by the standard, reclassified certain amounts in the financial statements for 2017 and 2016.

(c) The Company implemented ASU 2016-15, Statement of Cash Flows (Topic 230) in the first quarter of 2018, and as required

by the standard, reclassified certain amounts in the financial statements for 2017 and 2016.

24

 
 
Item 7. 

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

As you read this Management’s Discussion and Analysis of Financial Condition and Results of Operations, please refer to 

our Financial Statements and the accompanying notes, which contain our operating results.

Summary of Critical Accounting Policies and Estimates

Our financial statements have been prepared in conformity with U.S. Generally Accepted Accounting Principles ("GAAP"). 
Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to Financial Statements contains a summary of 
our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant 
accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, 
subjective assumptions by management, which can materially impact reported results. The Company evaluates its estimates on 
an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-
retirement obligations and asset retirement obligations ("ARO"). Changes in these estimates or assumptions, or actual results that 
are different, could materially impact our financial condition and results of operation.

Regulatory Accounting 

We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC 
jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize 
them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only 
when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, 
regulatory precedent and the current regulatory environment. As of December 31, 2018, we had recorded regulatory assets currently 
subject to recovery in future rates of approximately $81.8 million and regulatory liabilities of approximately $313.3 million as 
discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Notes E and K of Notes to Financial 
Statements. Regulatory tax assets of approximately $20.2 million related to the regulatory treatment of the equity portion of 
Allowance for Funds Used During Construction ("AFUDC") and approximately $19.3 million related to excess deferred state 
income taxes are included in regulatory assets. Regulatory tax liabilities of approximately $299.4 million, primarily related to the 
reduction of the corporate tax rate from 35% to 21%, are included in regulatory liabilities and will be refunded to customers.

In the event we determine that we can no longer apply the Financial Accounting Standards Board's ("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 by the PUCT or the NMPRC, we record fuel transactions such that fuel revenues, including 
fuel costs recovered through the FPPCAC in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery 
occurs during a reconciliation proceeding or an audit, the amounts recorded for fuel and purchased power expenses could differ 
from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.

On  September  27,  2016,  the  Company  filed  an  application  with  the  PUCT,  designated  as  PUCT  Docket  No.  46308,  to 
reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 
31, 2016. On June 29, 2017, the PUCT approved a settlement in this proceeding. The settlement provides for the reconciliation 
of  fuel  and  purchased  power  costs  incurred  from April  1,  2013  through  March  31,  2016. As  of  December  31,  2018,  Texas 
jurisdictional fuel and purchased power costs subject to prudence review are costs from April 1, 2016 through December 31, 2018 
that total approximately $353.4 million. The Company's request to reconcile its fuel and purchased power costs for the period 
January 1, 2013 through December 31, 2014 was approved in the NMPRC Final Order. New Mexico jurisdictional costs subject 
to prudence review are costs from January 1, 2015 through December 31, 2018 that total approximately $206.8 million.

The Company recovers fuel and purchased power costs from the Rio Grande Electric Cooperative ("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 

25

approved by the RGEC annually in February following the prior calendar year. As of December 31, 2018, the RGEC fuel costs 
subject to prudence review were approximately $1.1 million.

Decommissioning Costs and Estimated Asset Retirement Obligation

Pursuant to the ANPP Participation Agreement, the rules and regulations of the NRC 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 $98.8 million and represents approximately 98% of our total ARO balance of $101.1 million as of December 
31, 2018. A 10% increase in the estimates of future Palo Verde decommissioning costs at current price levels would have increased 
the ARO liability by approximately $10.9 million at December 31, 2018. See Part II, Item 8, Financial Statements and Supplementary 
Data, Note F of Notes to Financial Statements for further discussion.

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

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

The NDT consists 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 
$134.2 million as of December 31, 2018. A hypothetical 10% increase in interest rates would have reduced the fair values of these 
funds by $1.7 million at December 31, 2018. The NDT also includes marketable equity securities of approximately $135.9 million 
at December 31, 2018. A hypothetical 10% decrease in equity prices would have reduced the fair values of these funds by $13.6 
million at December 31, 2018. Declines in market prices could require that additional amounts be contributed to our NDT to 
maintain minimum funding requirements.

We do not anticipate expending monies held in the NDT 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, 2018 
totaled $114.0 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled 
$2.2 million for the twelve months ended December 31, 2018.

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 2018, 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, 2018, the corresponding weighted-average discount rates 
range from 4.11% to 4.45% depending upon the benefit plan.

Our overall expected long-term rate of return on assets for the pension trust fund is 7.5% as of January 1, 2019, 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 6.00% as of January 1, 2019. 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.

26

Our accrued post-retirement benefit liability and the service and interest components of the related net periodic benefit costs 
are calculated using an actuarial assumption regarding health care cost inflation. For measurement purposes, a 6.0%, 7.0%, 4.5% 
and 8.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019 for pre-65 medical, 
pre-65 drug, post-65 medical and post-65 drug, respectively. The health care cost trend rates are assumed to decline steadily to an 
ultimate rate of 4.5% by 2025 for pre-65 medical and by 2026 for pre-65 and post-65 drug. Post-65 medical trend is assumed to 
be 4.5% for all years into the future. Assumed health care cost trend rates have a significant effect on the amounts reported for the 
health care plan.

The estimated rate of compensation increase used in our retirement plans is 4.5% and is based on recent trends for all non-

union employees and the amounts we are contractually obligated for union employees.

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

31, 2018 reported pension liability and our 2018 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

$

(42,264)
52,315

$

N/A

N/A

8,256
(7,429)

(4,024)
4,951

(2,811)
2,811

1,773
(1,555)

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

31, 2018 other post-retirement benefit obligation and our 2018 reported other post-retirement 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

$

(8,132)
10,426

$

(1,171)
1,539

$

9,886
(7,769)

N/A

N/A

2,065
(1,568)

(398)
398

(384)
516

1,200
(890)

N/A

N/A

27

Tax Accruals

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets 
and  liabilities  for  the  future  tax  consequences  attributable  to  temporary  differences  between  the  financial  statement  carrying 
amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we 
make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation 
or audit adjustments can materially affect amounts we recognize in our financial statements. On December 22, 2017, the TCJA 
was enacted. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. 
The TCJA includes significant changes to the IRC, including amendments which significantly change the taxation of business 
entities  and  includes  specific  provisions  related  to  regulated  public  utilities.  See  Part  II,  Item  8,  Financial  Statements  and 
Supplementary Data, Note K of Notes to Financial Statements for further discussion.

When appropriate, we record a valuation allowance against deferred tax assets to reflect that these tax assets may not be 
realized. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and 
character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the 
results of operations and financial position of the Company. There were no valuation allowances for deferred tax assets as of 
December 31, 2018.

We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount 
recognized  is  measured  as  the  largest  amount  of  benefit  that  is  greater  than  50%  likely  to  be  realized  upon  settlement. The 
unrecognized tax benefits that do not meet the recognition and measurement standards were $3.2 million as of December 31, 2018.

The following is an overview of our results of operations for the years ended December 31, 2018, 2017 and 2016. Net income 

and basic earnings per share for the years ended December 31, 2018, 2017 and 2016 are shown below:

Overview

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

$

84,315
2.07

$

98,261
2.42

96,768
2.39

Years Ended December 31,

2018

2017

2016

28

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

between the calendar years ended December 31, 2018 and 2017, 2017 and 2016, and 2016 and 2015 (in thousands): 

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

(Decreased) increased investment and interest income, NDT .........
(Increased) decreased depreciation and amortization ......................
Palo Verde performance rewards, net...............................................
Increased operations and maintenance expenses at fossil-fuel
generating plants ..............................................................................
Increased interest on long-term debt (net of capitalized interest)
and other ...........................................................................................
(Decreased) increased retail non-fuel base revenues .......................
Increased taxes other than income taxes ..........................................
Effective tax rate, other ....................................................................
Decreased (increased) Palo Verde operations and maintenance
expenses ...........................................................................................
Increased (decreased) allowance for funds used during
construction ......................................................................................
Other.................................................................................................
Current year December 31 net income............................................. $

2018

2017

2016

98,261   

$

96,768   

$

81,918   

(18,419) (a)
(4,377) (c)
(3,954) (f)

2,508 (b)
(4,242) (d)
3,253 (f)

(2,518) (g)

(482)

(1,718) (h)
(520) (k)
(108)
16,643 (p)

(1,632) (i)
8,651 (l)
(3,465) (n)
3,379 (q)

(2,709) (b)
3,580 (e)

—

(330)

(3,694) (j)
28,802 (m)
(1,168) (o)
(5,343) (r)

2,299 (s)

(1,592) (t)

471

931
(2,205)
84,315   

(5,303) (u)
418

(4,887) (v)
128

$

98,261   

$

96,768   

______________________ 
Footnotes reflect pre-tax amounts
(a)

Investment and interest income, NDT decreased in 2018, primarily due to net realized and unrealized losses on securities
held in the NDT. Beginning on January 1, 2018, the Company adopted ASU 2016-01, Financial Instruments, and began
recording unrealized gains and losses on equity securities held in the NDT directly in earnings. Refer to "Impact of New
Accounting Standards and Use of Non-GAAP Financial Measures" for further details.
Investment and interest income, NDT increased in 2017 and decreased in 2016, primarily due to changes in realized gains
on securities sold from the NDT. Sales of such securities are primarily the result of the Company's efforts to re-balance
and further diversify the NDT investments.
Depreciation and amortization increased primarily due to increases in plant.
Depreciation and amortization increased primarily due to increases in plant, including MPS Units 3 and 4, which were
placed in service in 2016. These increases were partially offset by the sale of the Company's interest in Four Corners in
July 2016.
Depreciation and amortization decreased primarily due to (i) a reduction of approximately $10.9 million resulting from
changes in depreciation rates approved in the PUCT Final Order in Docket No. 44941 ("2016 PUCT Final Order") and
the NMPRC Final Order and (ii) the sale of the Company's interest in Four Corners in 2016. These decreases were partially
offset by an increase in plant, primarily due to MPS Units 1 and 2 and the Eastside Operations Center ("EOC") each
being placed in service in March 2015, and MPS Units 3 and 4 being placed in service in May 2016 and September 2016,
respectively.
Palo Verde performance rewards, associated with the 2013 to 2015 performance periods, net of disallowed fuel and
purchased power costs related to the resolution for the Texas fuel reconciliation proceeding designated as PUCT Docket
No. 46308 for the period from April 2013 through March 2016, were recorded in June 2017, with no comparable amounts
in 2018 or 2016.
O&M expenses at our fossil-fuel generating plants increased primarily due to outage costs at Rio Grande Unit 8 in 2018.
Interest on long-term debt (net of capitalized interest) and other increased, primarily due to the $125.0 million aggregate
principal amount of 4.22% Senior Notes issued in June 2018 and due in August 2028, partially offset by the redemption
of $33.3 million of 2012 Series A 1.875% Pollution Control Bonds ("PCBs") in 2017.
Interest on long-term debt (net of capitalized interest) and other increased, primarily due to the $150.0 million principal
amount of senior notes issued in March 2016 and an increase in short term borrowings for working capital purposes in
2017.
Interest on long-term debt (net of capitalized interest) and other increased, primarily due to the $150.0 million principal
amount of senior notes issued in March 2016.
Retail non-fuel base revenues decreased primarily due to refunds of approximately $28.2 million for the reduction in the
federal corporate income tax rate due to the TCJA, partially offset by a $7.7 million base rate increase compared to 2017

29

(b)

(c)
(d)

(e)

(f)

(g)
(h)

(i)

(j)

(k)

base rate increase related to the 2017 PUCT Final Order. Excluding the impact of rate changes, retail non-fuel base 
revenues in 2018, increased by $19.8 million primarily due to an increase in kWh sales that resulted from favorable 
weather and an increase in the average number of customers served.
Retail non-fuel base revenues increased primarily due to the non-fuel base rate increase approved in the 2017 PUCT
Final Order. 2017 included approximately $8.8 million of retail non-fuel base revenues for the period from July 18, 2017
through December 31, 2017, which was recognized when the 2017 PUCT Final Order was approved in December 2017.
Excluding the $8.8 million 2017 PUCT Final Order impact, retail non-fuel base revenues increased $4.5 million, or 0.7%,
in 2017 compared to 2016.
Retail non-fuel base revenues increased primarily due to the recognition of $40.9 million related to the 2016 PUCT Final
Order.
Taxes other than income taxes increased primarily due to increased property valuations in Texas as a result of MPS Units
3 and 4 being placed in service in 2016 and increased revenue related taxes in Texas.
Taxes other than income taxes increased primarily due to increased property tax rates and valuations in Texas as a result
of MPS Units 1 and 2 and the EOC being placed in service during the first quarter of 2015 and increased billed revenues
for Texas revenue related taxes. These increases were partially offset by decreased property taxes in Arizona due to lower
property values.
The effective tax rate, other decreased primarily due to the TCJA that reduced the federal corporate income tax rate from
35% to 21%, excluding the tax impact of other items in the table above partially offset by a reduction in state tax reserves
in 2017 due to the favorable settlement of Texas state income tax audits.
The effective tax rate, other decreased primarily due to favorable settlements of state income tax audits in Texas and
Arizona.
The effective tax rate, other increased primarily due to the change to normalize state income taxes in accordance with
the 2016 PUCT Final Order and the NMPRC Final Order.
Palo Verde O&M expenses decreased primarily due to lower incentives and administrative and general ("A&G") benefits
in 2018 compared to 2017.
Palo Verde O&M expenses increased primarily due to higher A&G expenses.
AFUDC decreased due to lower balances of construction work in progress ("CWIP"), primarily due to MPS Units 3 and
4 being placed in service in May and September 2016, respectively, and a reduction in the AFUDC rate effective January
2017.
AFUDC decreased due to lower balances of CWIP, primarily due to the MPS units and the EOC being placed in service
in 2015 and 2016, and a reduction in the AFUDC rate effective January 2016 as a result of the 2016 PUCT Final Order.

(l)

(m)

(n)

(o)

(p)

(q)

(r)

(s)

(t)
(u)

(v)

30

Impact of New Accounting Standard and Use of Non-GAAP Financial Measures

Upon adoption of ASU 2016-01, Financial Instruments - Recognition and Measurement of Financial Assets and Financial 
Liabilities, the Company recorded, as of January 1, 2018, a cumulative effect adjustment to retained earnings of $41.0 million, 
net of tax, for the unrealized gains (losses) related to equity securities held in the NDT. As required by ASU 2016-01, changes in 
the fair value of equity securities are now recognized in the Company's Statements of Operations. The adoption of the new standard 
added the potential for significant volatility to the Company's reported results of operations as changes in the fair value of equity 
securities  may  occur.  Furthermore,  the  equity  investments  included  in  the  NDT  are  significant  and  are  expected  to  increase 
significantly during the remaining life (estimated to be 27 to 30 years) of Palo Verde. Accordingly, the Company has provided the 
following non-GAAP financial measures, which reconcile GAAP net income to non-GAAP adjusted net income and GAAP basic 
earnings per share to non-GAAP adjusted basic earnings per share, to exclude the impact of changes in fair value of equity securities 
and realized gains (losses) from the sale of both equity and fixed income securities.

Twelve Months Ended

December 31,

2017

2016

2018

(In thousands except for per share data)

Net income (GAAP)

$

84,315

$

98,261

$

96,768

Adjusting items before income tax effects

Unrealized losses, net
Realized gains, net

Total adjustments before income tax effects

Income taxes on above adjustments

Adjusting items, net of income taxes

Adjusted net income (non-GAAP)

Basic earnings per share (GAAP)
Adjusted basic earnings per share (non-GAAP)

$

$
$

18,601
(5,634)
12,967
(2,593)
10,374
94,689

2.07
2.33

$

$
$

—
(10,626)
(10,626)
2,125
(8,501)
89,760

2.42
2.21

$

$
$

—
(7,640)
(7,640)
1,528
(6,112)
90,656

2.39
2.24

Adjusted net income and adjusted basic earnings per share are not measures of financial performance under GAAP and 
should  not  be  considered  as  an  alternative  to  net  income  and  earnings  per  share,  respectively.  Furthermore,  the  Company's 
presentation of any non-GAAP financial measure may not be comparable to similarly titled measures used by other companies. 
The Company believes adjusted net income and adjusted basic earnings per share are useful financial measures for investors and 
analysts in understanding the Company's core operating performance because each measure removes the effects of variances 
reported in the Company's results of operations that are not indicative of fundamental changes in the earnings capacity of the 
Company.

31

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 to our sole full requirement customer (which are FERC-regulated 
cost-based wholesale sales within our service territory), accounted for less than 1% of revenues in each of 2018, 2017 and 2016.

Revenues  from  the  sale  of  electricity  include  fuel  costs  that  are  recovered  from  our  customers  through  fuel  adjustment 
mechanisms. Prior to 2017, a significant portion of fuel costs have been recovered through base rates in New Mexico. Effective 
July 1, 2016, with the implementation of the NMPRC Final Order, fuel costs are no longer recovered through base rates. Beginning 
July 1, 2016, all fuel costs are recovered through a fuel adjustment mechanism. We record deferred fuel revenues for the difference 
between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. "Non-
fuel base revenues" refers to our revenues from the sale of electricity excluding such fuel costs.

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

Years Ended December 31,

2018

2017

2016

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

48%
31
6
15
100%

46%
32
6
16
100%

46%
32
6
16
100%

No retail customer accounted for more than 3% of our non-fuel base revenues during such periods. As shown in the table 
above, residential and small commercial customers represent approximately 79% of our non-fuel base revenues. While this customer 
base is more stable, it is also more sensitive to changes in weather conditions. The current rate structures in Texas and New Mexico 
reflect higher base rates during the peak summer season of May through October and lower base rates during November through 
April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh 
sales and revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base 
revenues derived during each quarter for the periods presented:

Years Ended December 31,

2018

2017

2016

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

18%
28
34
20
100%

18%
27
34
21
100%

17%
25
38
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 2018, 2017 and 2016.

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

3,174
1,937

2,917
1,522

2,811
1,851

2018

2017

2016

10-year
Average

2,863
2,056

32

 
 
 
Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew 1.6% and 1.7% 
in 2018 and 2017, respectively. See the tables presented on pages 35 and 36 which provide detail on the average number of retail 
customers and the related revenues and kWh sales.

Retail non-fuel base revenues. For the twelve months ended December 31, 2018, retail non-fuel base revenues decreased 
primarily due to the refunds in 2018 of approximately $28.2 million to customers for the reduction in the federal corporate income 
tax rate due to the TCJA, partially offset by a $7.7 million base rate increase related to the 2017 PUCT Final Order. Excluding the 
impact of rate changes related to the 2017 PUCT Final Order, retail non-fuel base revenues increased by $19.8 million, or 3.2%, 
compared to the twelve months ended December 31, 2017. This increase was primarily due to (i) increased revenues from residential 
customers of $17.1 million caused by a 5.9% increase in kWh sales that resulted from favorable weather and a 1.7% increase in 
the average number of residential customers served, and (ii) increased revenues from small commercial and industrial customers 
of $2.9 million that resulted from favorable weather and a 0.9% increase in the average number of small commercial and industrial 
customers served. Cooling degree days increased 8.8% in the twelve months ended December 31, 2018, when compared to the 
twelve months ended December 31, 2017, and were 10.9% above the 10-year average. Heating degree days increased 27.3% in 
the twelve months ended December 31, 2018, when compared to the twelve months ended December 31, 2017, and were 5.8% 
below the 10-year average.

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

Fuel revenues. Fuel revenues consist of (i) revenues collected from customers under fuel recovery mechanisms approved 
by the state commissions and the FERC, (ii) deferred fuel revenues which, are comprised of the difference between fuel costs and 
fuel revenues collected from customers, and (iii) prior to July 1, 2016, fuel costs recovered in base rates in New Mexico. In New 
Mexico, effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs are no longer 
recovered through base rates, as they were historically, but are recovered through the FPPCAC. Fuel and purchased power costs 
are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. Additionally, 
effective January 1, 2018, pursuant to the final order in NMPRC Case No. 17-00090-UT, the RPS costs for New Mexico are 
recovered through a separate RPS Cost Rider and not through the FPPCAC. The RPS Cost Rider is updated in an annual NMPRC 
filing, including a true-up of the prior calendar year’s RPS costs and RPS Cost Rider revenue. In Texas, fuel costs are recovered 
through a fixed fuel factor. We can seek to revise our Texas fixed fuel factor based upon an approved formula at least four months 
after our last revision, except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to 
refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over-
and under-recoveries are defined as material when they exceed 4% of the previous twelve months' fuel costs.

In March 2018 and March 2017, $1.1 million and $1.4 million, respectively, were credited to customers through the applicable 

fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage.

We over-recovered fuel costs by $4.8 million in the twelve months ended December 31, 2018. We over-recovered fuel costs 
by $17.1 million and under-recovered fuel costs by $14.9 million in the twelve months ended December 31, 2017 and 2016, 
respectively. At December 31, 2018, we had a net fuel over-recovery balance of $11.0 million, including over-recoveries of $8.9 
million in Texas, $2.0 million in New Mexico and $0.1 million in FERC jurisdictions. On October 13, 2017, we filed a request to 
decrease our Texas fixed fuel factor by approximately 19% to reflect decreased fuel expenses primarily related to a decrease in 
the price of natural gas used to generate power. The decrease in our Texas fixed fuel factor became effective beginning with the 
November 2017 billing month. On April 13, 2018, we filed a request with the PUCT to decrease the Texas fixed fuel factor by 
approximately 29% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate 
power. On April 25, 2018, our proposed fuel factors were approved on an interim basis effective for the first billing cycle of the 
May 2018 billing month. The revised factor was approved and the docket closed on May 22, 2018. On October 15, 2018, we filed 
a request with the PUCT to decrease our Texas fixed fuel factor by approximately 6.99% to reflect decreased fuel expenses primarily 
related to a decrease in the price of natural gas used to generate power. On October 25, 2018, our fixed fuel factor was approved 
on an interim basis effective for the first billing cycle of the November 2018 billing month. The revised factor was approved by 
the PUCT and the docket closed on November 19, 2018. The Texas fixed fuel factor will continue thereafter until changed by the 
PUCT.

33

Off-system sales. Off-system sales are sales into wholesale markets outside our service territory. Off-system sales are primarily 
made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. 
We have shared 100% of margins on non-arbitrage sales (as defined by the settlement in PUCT Docket No. 41852) and 50% of 
margins on arbitrage sales with our Texas customers since April 1, 2014. We are currently sharing 90% of off-system sales margins 
with our New Mexico customers (as reaffirmed in NMPRC Case No. 09-00171-UT), and 25% of our off-system sales margins 
with our sales for resale - full requirement customer under the terms of their contract.

Typically, we realize a significant portion of our off-system sales margins in the first and fourth 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. A decrease in natural gas market prices coupled 
with an increase in wholesale power market prices allowed us to engage in additional off-system sales in the third quarter of 2018 
and in the third quarter of 2017. Palo Verde's availability is an important factor in realizing these off-system sales margins.

The table below shows megawatt-hours ("MWhs"), sales revenue, fuel cost, total margins and retained margins made on 

off-system sales for the twelve months ended December 31, 2018, 2017 and 2016 (in thousands, except for MWhs).

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

Years Ended December 31,

2018

2,687,961
86,418
54,299
32,119
2,129

2017

2,042,884
58,986
46,258
12,728
1,673

$
$
$
$

2016

1,927,508
45,702
38,933
6,769
1,137

$
$
$
$

Off-system sales revenue increased $27.4 million, or 46.5%, and the related retained margins increased $0.5 million, or 
27.3%, for the twelve months ended December 31, 2018, when compared to the twelve months ended December 31, 2017, as a 
result of a 31.6% increase in MWh sales due to additional available power, and higher average market prices for power. Off-system 
sales revenue increased $13.3 million, or 29.1%, and the related retained margins increased $0.5 million, or 47.1%, for the twelve 
months ended December 31, 2017, when compared to the twelve months ended December 31, 2016, as a result of higher average 
market prices for power and a 6.0% increase in MWh sales due to additional available power.

34

 
 
Comparisons of kWh sales and operating revenues are shown below: 

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

Retail:

2018

2017

Amount

Percent

Increase (Decrease)

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

2,988,695
2,431,920
1,050,834
1,563,227
8,034,676

Wholesale:

Sales for resale - full requirement customer .................
Off-system sales............................................................
Total wholesale sales..........................................
Total kWh sales ..........................................

58,991
2,687,961
2,746,952
10,781,628

2,823,260
2,410,710
1,045,319
1,564,670
7,843,959

62,887
2,042,884
2,105,771
9,949,730

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 (1) (2) .

Wholesale:

Sales for resale - full requirement customer.......
Total non-fuel base revenues......................

Fuel revenues:

Recovered from customers during the period ...............
Over collection of fuel (3).............................................
Total fuel revenues (4) (5)..........................
Off-system sales (6) ..............................................................
Wheeling revenues (7) ..........................................................
Energy efficiency cost recovery (8) ......................................
Miscellaneous (7)..................................................................
Total revenues from customers...................
Other (7) (9) ..........................................................................

Average number of retail customers (10):

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

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

$

$

297,597
194,341
34,920
95,460
622,318

2,780
625,098

156,493
(4,736)
151,757
86,418
19,026
8,888
8,188
899,375
4,228
903,603

374,138
42,349
48
5,746
422,281

$

$

287,884
198,799
38,403
97,890
622,976

2,730
625,706

218,380
(17,133)
201,247
58,986
18,114
—
8,229
912,282
4,515
916,797

368,044
41,978
48
5,532
415,602

165,435
21,210
5,515
(1,443)
190,717

(3,896)
645,077
641,181
831,898

9,713
(4,458)
(3,483)
(2,430)
(658)

50
(608)

(61,887)
12,397
(49,490)
27,432
912
8,888
(41)
(12,907)
(287)
(13,194)

6,094
371
—
214
6,679

5.9%
0.9
0.5
(0.1)
2.4

(6.2)
31.6
30.4
8.4

3.4%
(2.2)
(9.1)
(2.5)
(0.1)

1.8
(0.1)

(28.3)
72.4
(24.6)
46.5
5.0
—
(0.5)
(1.4)
(6.4)
(1.4)

1.7%   
0.9
—   
3.9
1.6

 ___________________________
(1)

(2)
(3)

(4)
(5)
(6)
(7)
(8)

2018 includes $7.7 million of additional revenues compared to 2017 resulting from the 2017 PUCT Final Order, which increased base rates effective July 
18, 2017. 
2018 includes a $28.2 million base rate decrease related to the reduction in the federal statutory income tax rate enacted under the TCJA.
Includes the portion of DOE refunds related to spent fuel storage of $1.1 million and $1.4 million in 2018 and 2017, respectively, that were credited to
customers through the applicable fuel adjustment clauses.
2017 includes $5.0 million related to the Palo Verde performance rewards, net.
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $8.1 million and $9.8 million in 2018 and 2017, respectively.
Includes retained margins of $2.1 million and $1.7 million in 2018 and 2017, respectively.
Represents revenues with no related kWh sales.
The Company implemented ASU 2014-09, Revenue from Contracts with Customers, in the first quarter of 2018, and following the adoption of the standard, 
revenues related to reimbursed costs of energy efficiency programs approved by the Company's regulators are reported in operating revenues from customers. 
Related expenses are reported in O&M expenses.
Includes energy efficiency bonuses of $1.3 million and $1.5 million in 2018 and 2017, respectively. 

(9)
(10) The number of retail customers presented is based on the number of service locations. 

35

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

Retail:

2017

2016

Amount

Percent

Increase (Decrease)

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

Wholesale:

Sales for resale - full requirement customer .................
Off-system sales............................................................
Total wholesale sales..........................................
Total kWh sales ..........................................

2,823,260
2,410,710
1,045,319
1,564,670
7,843,959

62,887
2,042,884
2,105,771
9,949,730

2,805,789
2,403,447
1,030,745
1,572,510
7,812,491

62,086
1,927,508
1,989,594
9,802,085

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 (1).......

Wholesale:

Sales for resale - full requirement customer.......
Total non-fuel base revenues......................

Fuel revenues:

Recovered from customers during the period ...............
Under (over) collection of fuel (2)................................
New Mexico fuel in base rates (3) ................................
Total fuel revenues (4) (5)..........................
Off-system sales (6) ..............................................................
Wheeling revenues (7) ..........................................................
Miscellaneous (7)..................................................................
Total revenues from customers...................
Other (7) (8) ..........................................................................

Average number of retail customers (9):

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

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

$

$

287,884
198,799
38,403
97,890
622,976

2,730
625,706

218,380
(17,133)
—
201,247
58,986
18,114
8,229
912,282
4,515
916,797

368,044
41,978
48
5,532
415,602

$

$

278,774
194,942
39,070
96,881
609,667

2,407
612,074

148,397
14,893
33,279
196,569
45,702
21,966
7,034
883,345
3,591
886,936

362,138
41,014
49
5,303
408,504

17,471
7,263
14,574
(7,840)
31,468

801
115,376
116,177
147,645

9,110
3,857
(667)
1,009
13,309

323
13,632

69,983
(32,026)
(33,279)
4,678
13,284
(3,852)
1,195
28,937
924
29,861

5,906
964
(1)
229
7,098

0.6%
0.3
1.4
(0.5)
0.4

1.3
6.0
5.8
1.5

3.3%
2.0
(1.7)
1.0
2.2

13.4
2.2

47.2
—
—
2.4
29.1
(17.5)
17.0
3.3
25.7
3.4

1.6%   
2.4
(2.0)
4.3
1.7

 _______________________
(1)

2017 includes $8.8 million of relate back revenues in Texas from July 18, 2017 through December 31, 2017, which was recorded in the fourth quarter of
2017 related to the 2017 PUCT Final Order.
Includes the portion of DOE refunds related to spent fuel storage of $1.4 million and $1.6 million in 2017 and 2016, respectively, that were credited to
customers through the applicable fuel adjustment clauses.
Historically, fuel and purchased power costs in the New Mexico jurisdiction were recorded through base rates and a FPPCAC that accounts for the changes 
in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the NMPRC Final Order, these costs 
are no longer recovered through base rates but are recovered through the FPPCAC.
2017 includes $5.0 million related to the Palo Verde performance rewards, net.
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.8 million and $8.7 million in 2017 and 2016, respectively.
Includes retained margins of $1.7 million and $1.1 million in 2017 and 2016, respectively.
Represents revenues with no related kWh sales.
Includes an energy efficiency bonuses of $1.5 million and $0.5 million in 2017 and 2016, respectively. 
The number of retail customers presented is based on the number of service locations. 

(2)

(3)

(4)
(5)
(6)
(7)
(8)
(9)

36

 
 
 
 
 
  
  
  
  
Fuel and purchased power expense

Our sources of energy include electricity generated from our nuclear and natural gas generating plants and purchased power. 
Palo Verde represents approximately 30% of our net dependable generating capacity and approximately 49% of our Company-
generated energy for the twelve months ended December 31, 2018. 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.

Fuel and purchased power expense decreased $15.6 million, or 6.4%, for the twelve months ended December 31, 2018 
compared to the twelve months ended December 31, 2017, primarily due to (i) decreased natural gas costs of $12.6 million primarily 
due to a 30.4% decrease in the average cost of MWhs generated, partially offset by a 30.9% increase in the MWhs generated with 
natural gas, and (ii) decreased nuclear fuel costs of $3.1 million primarily due to a reduction in the price of uranium and a 3.8% 
decrease in the MWhs generated with nuclear fuel.

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

The table below details the sources and costs of energy for 2018, 2017 and 2016. 

Fuel Type

Cost

2018

MWh

Cost per
MWh

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

(in thousands)
129,583

661 (a)
39,118 (b)
169,362   

$

5,029,863
—
4,913,858
9,943,721

Purchase Power:

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

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

22,228
37,519
59,747   
229,109   

275,569
1,079,740
1,355,309
11,299,030

25.76
—
8.20
17.15

80.66
34.75
44.08
20.38

2017

MWh

Cost per
MWh

Cost

(in thousands)
142,227
$

575 (a)
42,267 (b)
185,069

$

3,841,550
—
5,109,325
8,950,875

23,784
35,898
59,682
244,751

292,157
1,248,684
1,540,841
   10,491,716

$

37.02
—
8.58
20.85

81.41
28.75
38.73
23.48

Fuel Type

Cost

2016

MWh

Cost per
MWh

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

(in thousands)
123,806

6,154 (a)
43,778 (b)
173,738

$

3,550,904
175,258
5,093,844
8,820,006

Purchase Power:

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

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

23,413
36,314
59,727   
233,465

289,800
1,262,451
1,552,251
10,372,257

34.87
35.11
8.94
19.90

80.79
28.76
38.48
22.68

__________________ 
(a) The sale of our interest in Four Corners, a coal-fired generation station, closed on July 6, 2016. The cost includes the amortization of
deferred coal mine reclamation obligations.
(b) Costs include a DOE refund related to spent fuel storage of $1.2 million, $1.6 million and $1.8 million recorded in 2018, 2017 and 2016,
respectively. Cost per MWh excludes these refunds.

37

 
 
 
 
 
 
 
 
  
  
 
 
 
 
 
 
 
 
 
 
 
 
 
Operations and maintenance expense 

O&M expense increased $14.6 million, or 4.6%, in 2018 compared to 2017, primarily due to increases of (i) $8.9 million 
related to energy efficiency program costs previously offset by the related revenues prior to the adoption of ASU 2014-09, (ii) 
$3.3 million in outage costs at Rio Grande Unit 8, (iii) $2.4 million in transmission and distribution expense primarily due to 
increases in payroll costs and Palo Verde transmission expenses due to storm repairs, and (iv) $1.9 million in Four Corners operating 
expenses due to an adjustment in estimated pension and benefit costs and post-closing purchase price adjustments recorded in 
2017. These increases were partially offset by a $2.9 million decrease in Palo Verde O&M expense primarily due to lower incentives 
and A&G benefits in 2018.

O&M expense increased $4.6 million, or 1.4%, in 2017 compared to 2016, primarily due to increases of (i) $7.1 million in 
maintenance outages at Newman Units 1, 3 and 4, (ii) $3.9 million in maintenance costs at Newman and MPS, (iii) $2.4 million 
in Palo Verde O&M expenses primarily due to higher A&G expenses, and (iv) $3.0 million in various other operating costs. These 
increases were partially offset by a decrease of $12.1 million in O&M costs in 2017 as a result of the sale of our interest in Four 
Corners in July 2016. 

Depreciation and amortization expense

Depreciation and amortization expense increased $5.5 million, or 6.1%, in 2018 compared to 2017, primarily due to increases 

in plant, including distribution, general, Palo Verde and intangible plant.

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

Taxes other than income taxes

Taxes other than income taxes increased $0.1 million, or 0.2%, in 2018 compared to 2017, primarily due to increased property 

tax rates and valuations, partially offset by decreased revenue related taxes in Texas.

Taxes other than income taxes increased $5.3 million, or 8.1%, in 2017 compared to 2016, primarily due to increased property 
tax rates and valuations in Texas as a result of MPS Units 3 and 4 being placed in service in 2016 and increased billed revenues 
in Texas.

38

Other income (deductions)

Other income (deductions) decreased $19.7 million, or 46.5%, in 2018 compared to 2017, primarily due to a $23.6 million 
increase in net realized and unrealized losses on securities held in the NDT. During the fourth quarter of 2018, the U.S. equity 
markets experienced the greatest overall fourth quarter declines since 2008. This decrease was partially offset by a $2.4 million 
increase in the expected return on benefit plan assets. Beginning on January 1, 2018, the Company adopted ASU 2016-01, Financial 
Instruments, and began recording unrealized gains and losses on equity securities held in the NDT directly in earnings. Further 
details are shown below (in thousands):

Allowance for equity funds used during construction... $
Investment and interest income, net:

NDT unrealized losses, net .......................................
NDT realized gains, net ............................................
NDT dividends and interest income .........................
Expected returns on benefit plans (ASU 2017-07)...
Other .........................................................................

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

Total other income (deductions) .......................... $

Years Ended December 31,

2018

2017

2016

3,453

$

3,025

$

7,023

(18,601)
5,634

7,227

23,511

606

18,377

12,823
(11,980)
22,673

$

—

10,626

6,698

21,096

433

38,853

12,051
(11,580)
42,349

$

—

7,640

6,498

20,714
(55)
34,797

11,073
(11,038)
41,855

Other income (deductions) increased $0.5 million, or 1.2%, in 2017 compared to 2016, primarily due to a $3.0 million 
increase in net realized gains on securities held in the NDT. This increase was partially offset by a $4.0 million decrease in AEFUDC 
resulting from lower average balances of CWIP and a reduction in the Allowance for Equity Funds Used During Construction 
("AEFUDC") rate. 

Interest charges (credits)

Interest charges (credits) increased by $1.1 million, or 1.3%, in 2018 compared to 2017, primarily due to interest expense 
on the $125.0 million aggregate principal amount of 4.22% Senior Notes issued in June 2018 and due in August 2028, partially 
offset by (i) a net decrease in the interest cost component of net periodic benefit cost of the Company's employee benefit plans, 
(ii) increased allowance for borrowed funds used during construction ("ABFUDC") as a result of an increase in the ABFUDC rate
and higher average balances of CWIP, and (iii) the redemption of $33.3 million of 2012 Series A 1.875% PCBs in 2017.

Interest charges (credits) increased by $4.1 million, or 5.1%, in 2017 compared to 2016, primarily due to decreased ABFUDC 
as a result of lower average balances of CWIP and a reduction in the ABFUDC rate and interest expense on the $150.0 million 
aggregate principal amount of 5.00% Senior Notes due 2044 issued in March 2016.

Income tax expense

Income tax expense decreased by $24.6 million, or 48.3%, in 2018 compared to 2017, primarily due to a decrease in the 
federal corporate income tax rate from 35% to 21% and a 25.8% reduction in pre-tax income, partially offset by a reduction in 
state tax reserves in 2017 due to the favorable settlement of Texas state income tax audits. 

Income tax expense decreased by $2.9 million, or 5.4%, in 2017 compared to 2016, primarily due to favorable settlements 

of state income tax audits in Texas and Arizona.

New accounting standards adopted and to be adopted in the future

See Part II, Item 8, Financial Statements and Supplementary Data, Note B of Notes to Financial Statements for discussion 

on new accounting standards adopted and to be adopted in the future.

39

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

At December 31, 2018, our capital structure, including common stock, long-term debt, current maturities of long-term debt, 
and short-term borrowings under our RCF, consisted of 44.8% common stock equity and 55.2% debt. As of December 31, 2018, 
we had a balance of $12.9 million in cash and cash equivalents. Based on current projections, we believe that we will have adequate 
liquidity through our current cash balances, cash from operations, available borrowings under the RCF, and debt or equity issuances 
in the capital markets to meet all of our anticipated cash requirements over 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, 2018, our capital requirements primarily consisted 
of expenditures for the construction and purchase of electric utility plant, payment of common stock dividends and purchases of 
nuclear  fuel.  Projected  utility  construction  expenditures  are  to  add  new  generation,  expand  and  update  our  transmission  and 
distribution  systems,  make  capital  improvements  and  replacements  at  Palo Verde  and  other  generating  facilities,  and  make 
investments in other property and equipment. Estimated cash construction expenditures for all capital projects for 2019 are expected 
to be approximately $249 million. See Part I, Item 1, "Business - Construction Program." Cash capital expenditures for new electric 
plant were $240.0 million in the twelve months ended December 31, 2018, compared to $199.9 million in the twelve months ended 
December 31, 2017. Capital requirements for purchases of nuclear fuel were $38.4 million for the twelve months ended December 
31, 2018, as compared to $38.5 million for the twelve months ended December 31, 2017.

On December 28, 2018, we paid a quarterly cash dividend of $0.36 per share, or $14.6 million, to shareholders of record as 
of the close of business on December 14, 2018. We paid a total of $57.5 million in cash dividends during the twelve months ended 
December 31, 2018. On January 31, 2019, our Board of Directors declared a quarterly cash dividend of $0.36 per share payable 
on March 29, 2019, to shareholders of record as of the close of business on March 15, 2019. Typically, the Board of Directors 
reviews  our  dividend  policy  annually  in  the  second  quarter  of  each  year.  In  addition,  while  we  do  not  currently  anticipate 
repurchasing shares of our common stock in 2019, we may repurchase shares of our common stock in the future. Under our 
repurchase program, purchases can be made at open market prices or in private transactions, and repurchased shares are available 
for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were repurchased 
during the twelve months ended December 31, 2018. As of December 31, 2018, a total of 393,816 shares remain eligible for 
repurchase under the repurchase program.

We expect to continue to maintain a prudent level of liquidity and monitor market conditions for debt and equity securities. 
Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing to make investments in new 
electric plant and other assets in order to reliably serve our customers.

Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced 
by the timing of revenues and expenses recognized for income tax purposes. The following summary describes the major impacts 
of the TCJA on our liquidity.

The TCJA discontinued bonus depreciation for regulated utilities, which reduced tax deductions previously available to us 
for  2018  and  2019. The  decrease  in  tax  deductions  results  in  the  utilization  of  our  net  operating  loss  carryforwards  ("NOL 
carryforwards") and other carryforwards approximately one year earlier than previously anticipated and is expected to result in 
higher income tax payments beginning in 2020, after the full utilization of NOL and other carryforwards. However, due to the 
lower federal corporate income tax rate enacted by the TCJA, our future federal corporate income tax payments will be made at 
the reduced rate of 21% beginning in 2018. Due to NOL and other carryforwards, minimal tax payments are expected for 2019, 
which are mostly related to state income taxes.

The effect of the TCJA on our rates is beneficial to our customers. Following the enactment of the TCJA and the reduction 
of the federal corporate income tax rate, revenues collected from our customers in 2018 were reduced by $28.2 million, which 
negatively impacted our cash flows and a comparable amount is expected during 2019.

We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans and 
decommissioning trust funds. We contributed $9.2 million and $9.8 million to our retirement plans during the twelve months ended 

40

December 31, 2018, and 2017, respectively. We contributed $0.5 million to our other post-retirement benefit plans during both 
the twelve months ended December 31, 2018, and 2017. We contributed $2.1 million and $3.8 million to the NDT in 2018 and 
2017, respectively. We are in compliance with the funding requirements of the federal government for our benefit plans. In addition, 
with respect to our nuclear plant decommissioning trust, we are in compliance with the funding requirements of the federal law 
and the ANPP Participation Agreement. We will continue to review our funding for these plans in order to meet our future obligations.

Capital Resources. Cash provided by operations, $285.4 million for the twelve months ended December 31, 2018, and $288.6 
million for the twelve months ended December 31, 2017, is a significant source for funding capital requirements. A component 
of cash flows from operations is the change in net over-collection and under-collection of fuel revenues. Cash from operations 
has been impacted by the timing of the recovery of fuel costs through fuel recovery mechanisms in Texas and New Mexico, and 
our sales for resale full requirement customer. We recover actual fuel costs from customers through fuel adjustment mechanisms 
in Texas and New Mexico, and from our sales for resale full requirement customer. We record deferred fuel revenues for the under-
recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered 
through a fixed fuel factor. We can seek to revise our fixed fuel factor at least four months after our last revision except in the 
month of December based upon our approved formula which allows us to adjust fuel rates to reflect changes in costs of natural 
gas. We are required to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material 
amount and we expect fuel costs to continue to be materially over-recovered. We are permitted to seek to surcharge fuel under-
recoveries in any month the balance exceeds a threshold material amount that we expect fuel cost recovery to continue to be 
materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve 
months' fuel costs. On October 15, 2018, we filed a request with the PUCT to decrease our Texas fixed fuel factor by approximately 
6.99% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. On 
October 25, 2018, our fixed fuel factor was approved on an interim basis effective for the first billing cycle of the November 2018 
billing month. The revised factor was approved by the PUCT and the docket closed on November 19, 2018. The Texas fixed fuel 
factor will continue thereafter until changed by the PUCT. During the twelve months ended December 31, 2018, we had over-
recoveries of fuel costs of $4.8 million compared to over-recoveries of fuel costs of $17.1 million during the twelve months ended 
December 31, 2017. At December 31, 2018, we had a net fuel over-recovery balance of $11.0 million, including over-recoveries 
of $8.9 million in Texas, $2.0 million in New Mexico, and $0.1 million in FERC jurisdictions. 

We maintain the RCF for working capital and general corporate purposes and financing nuclear fuel through the RGRT. The 
RGRT, the trust through which we finance our portion of nuclear fuel for Palo Verde, is consolidated in our financial statements. 
The total amount borrowed for nuclear fuel by the RGRT, excluding debt issuance costs, was $136.2 million at December 31, 
2018, of which $26.2 million had been borrowed under the RCF, and $110.0 million was borrowed through the issuance of senior 
notes. At December 31, 2017, the total amounts borrowed for nuclear fuel by the RGRT, excluding debt issuance costs, were 
$133.5 million, of which $88.5 million had been borrowed under the RCF and $45.0 million was borrowed through the issuance 
of 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 through fuel recovery charges. The outstanding balance under the RCF for working capital and general 
corporate purposes was $23.0 million at December 31, 2018, and $85.0 million at December 31, 2017. Total aggregate borrowings 
under the RCF as of December 31, 2018, were $49.2 million with an additional $300.7 million available to borrow. 

We received approval from the NMPRC on October 7, 2015, to guarantee the issuance of up to $65.0 million of long-term 
debt by the RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. We received 
additional approval from the NMPRC on October 4, 2017, to amend and extend the RCF, issue up to $350.0 million in long-term 
debt and to redeem and refinance the $63.5 million 2009 Series A 7.25% PCBs and the $37.1 million 2009 Series B 7.25% PCBs, 
which are subject to optional redemption in 2019. The NMPRC approval to issue up to $350.0 million in long-term debt supersedes 
its prior approval. We received approval from the FERC on October 31, 2017, to issue up to $350.0 million in long-term debt, to 
guarantee the issuance of up to $65.0 million of long-term debt by the RGRT, and to continue to utilize our existing RCF with the 
ability to amend and extend the RCF at a future date, and to redeem, refinance and/or replace the 2009 Series A and Series B PCBs 
with debt of equal face value. The authorization approved by the FERC is effective from November 15, 2017 through November 
14, 2019, and supersedes its prior approvals. 

Under these authorizations, on June 28, 2018, we issued $125 million in aggregate principal amount of 4.22% Senior Notes 
due August 15, 2028, and guaranteed the issuance by the RGRT of $65 million in aggregate principal amount of 4.07% Senior 
Guaranteed Notes due August 15, 2025. The net proceeds from the sale of these senior notes were used to repay outstanding short-
term borrowings under the RCF, which included borrowings made for working capital, general corporate purposes and the purchase 
of nuclear fuel. Also, under these authorizations, on September 13, 2018, we and RGRT entered into a third amended and restated 
credit agreement where we have available a $350.0 million RCF with a term ending on September 13, 2023. We may increase the 
RCF by up to $50.0 million (to a total of $400.0 million) during the term of the RCF, upon the satisfaction of certain conditions 
more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. In addition, 
we may extend the maturity date of the RCF up to two times, in each case for an additional one-year period, upon the satisfaction 
of certain conditions. Additionally, we are preparing for potential transactions related to the 2009 Series A and Series B PCBs. On 
41

February 1, 2019, we purchased in lieu of redemption all of the 2009 Series A PCBs utilizing funds borrowed under the RCF. We 
are currently holding the bonds and may remarket them or replace them with debt instruments of equivalent value at a future date 
depending on our financing needs and market conditions, and in accordance with FERC action expected in March 2019 in response 
to our most recent FERC application (see below).

On January 30, 2019, we submitted applications with both the NMPRC and the FERC seeking approval to issue shares of 
common stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more transactions. Included 
in the FERC application, we also requested various debt-related authorizations: approval to utilize the existing RCF for short-term 
borrowing not to exceed $400.0 million at any one time; to issue up to $225.0 million in new long-term debt; and to remarket the 
$63.5 million Series A PCBs and the $37.1 million Series B PCBs in the form of replacement bonds or senior notes of equivalent 
value, not to exceed $100.6 million. If approved, the FERC authorization would supersede its prior approvals.

42

Contractual Obligations. Our contractual obligations as of December 31, 2018 are as follows (in thousands): 

Long-term debt (including interest):

Senior notes (1)

Pollution control bonds (2)

RGRT senior notes (3)

Financing obligations (including interest):

Payments due by period

Total

2019

2020 and
2021

2022 and
2023

2024 and
Beyond

$ 2,202,925

$

60,475

$

120,950

$

266,000

$ 1,755,500

224,865

133,055

104,322

4,914

5,331

52,559

5,331

5,291

109,881

70,291

Revolving credit facility (4)

50,918

50,918

Purchase obligations:

Power contracts

Fuel contracts:

Gas (5)

Nuclear fuel (6)

Retirement plans and other post-retirement
benefits (7)

Nuclear Decommissioning Trust Funds (8)

Operating leases (9)

Total

 _____________________
(1)

23,874

23,874

366,292

84,580

9,904

57,569

8,991

42,203

21,177

9,904

2,132

923

—

—

68,590

24,175

—

4,264

1,520

—

—

70,254

17,503

—

4,264

1,070

—

—

185,245

21,725

—

46,909

5,478

$ 3,162,973

$

320,842

$

277,389

$

369,713

$ 2,195,029

We have five outstanding issuances of senior notes. In May 2005, we issued $400.0 million aggregate principal amount
of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150.0 million aggregate principal amount of 7.5%
Senior Notes due March 15, 2038. In December 2012, we issued $150.0 million aggregate principal amount of 3.3%
Senior Notes due December 15, 2022. In December 2014, we issued $150.0 million aggregate principal amount of 5.0%
Senior Notes due December 1, 2044. In March 2016, we issued an additional $150.0 million aggregate principal amount
of 5.0% Senior Notes due December 1, 2044, for a total principal amount outstanding of 5.0% Senior Notes due December
1, 2044 of $300.0 million. In June 2018, we issued in a private placement offering $125.0 million aggregate principal
amount of 4.22% Senior Notes due August 15, 2028.
We have three series of PCBs outstanding, two of which mature in 2040, and one of which matures in 2042. The 7.25%
2009 Series A and the 7.25% 2009 Series B PCBs with an aggregate principal amount, together, of $100.6 million have
optional redemptions beginning in February 2019 and April 2019, respectively, at which time we expect to redeem,
refinance or replace these bonds. On February 1, 2019, we purchased in lieu of redemption all of the 7.25% 2009 Series
A with a principal amount of $63.5 million utilizing funds borrowed under the RCF. We are currently holding the bonds
and may remarket them or replace them with debt instruments of equivalent value at a future date depending on our
financing needs and market conditions.
In 2010, we and RGRT entered into a note purchase agreement pursuant to which the RGRT issued and sold $45.0 million
aggregate principal amount of 5.04% RGRT Senior Notes, Series C, due August 15, 2020. In June 2018, we and RGRT
entered into a note purchase agreement pursuant to which the RGRT issued and sold $65.0 million aggregate principal
amount of 4.07% Senior Guaranteed Notes due August 15, 2025.
This reflects obligations outstanding under the $350.0 million RCF. At December 31, 2018, $23.0 million was borrowed
for working capital and general corporate purposes and $26.2 million was borrowed by RGRT for nuclear fuel. This
balance includes interest based on actual interest rates at the end of 2018 and assumes this amount will be outstanding
for the entire year of 2019.
Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2018. 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 2018.
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 2019. We have no minimum cash
contractual funding requirement related to our retirement income plan or other post-retirement benefits for 2019. However,
we are subject to minimum funding requirements of the Employee Retirement Income Security Act of 1974. We also
may decide to fund at higher levels and expect to contribute $9.9 million to our retirement plans in 2019. Minimum

(2)

(3)

(4)

(5)

(6)

(7)

43

 
 
 
(8)

(9)

funding requirements for 2020 and beyond are not included due to the uncertainty of the applicable interest rates and the 
related return on assets.
This obligation is based on the decommissioning funding allowed in PUCT Docket No. 46831, effective July 18, 2017.
We have no minimum funding obligation in the New Mexico jurisdiction effective July 1, 2016 with NMPRC Case No.
15-00127-UT. It is possible that our funding requirements could change based on the amounts allowed in future rate
filings.
We lease land in El Paso, Texas, adjacent to Newman under a lease that expires in June 2033, subject to a renewal option
of 25 years. We also have several other leases for office, parking facilities and equipment that expire within the next five
years.

Off-Balance Sheet Arrangements

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

44

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.

The NDT consists 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 
$134.2 million and $130.2 million as of December 31, 2018 and 2017, respectively. A hypothetical 10% increase in interest rates 
would reduce the fair values of the fixed income instruments by $1.7 million and $1.6 million at December 31, 2018 and 2017, 
respectively.

Equity Price Risk

The NDT includes marketable equity securities of approximately $135.9 million and $149.8 million at December 31, 2018 
and 2017, respectively. A hypothetical 10% decrease in equity prices would have reduced the fair values of the equity securities 
by $13.6 million and $15.0 million based on their fair values at December 31, 2018 and 2017, respectively. Declines in market 
prices could require that additional amounts be contributed to the NDT to maintain minimum funding requirements. We do not 
expect to expend monies held in the NDT before 2044 or a later period when decommissioning of Palo Verde begins.

Commodity Price Risk

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

In the normal course of business, we enter into contracts of various durations for the forward sales and purchases of electricity 
to effectively manage our available generating capacity and supply needs. Such contracts include forward contracts for the sale 
of generating capacity and energy during periods when our available power resources are expected to exceed the requirements of 
our retail native load and sales for resale. We also enter into forward contracts for the purchase of wholesale capacity and energy 
during periods when the market price of electricity is below our expected incremental power production costs or to supplement 
our generating capacity when demand is anticipated to exceed such capacity. As of January 31, 2019, 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.

45

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,  2018.  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, 2018, 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 48 of the Annual Report on Form 10-K.

46

Item 8. 

Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

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

Balance Sheets as of December 31, 2018 and 2017................................................................................................................

Statements of Operations for the years ended December 31, 2018, 2017 and 2016...............................................................

Statements of Comprehensive Operations for the years ended December 31, 2018, 2017 and 2016 ....................................

Statements of Changes in Common Stock Equity for the years ended December 31, 2018, 2017 and 2016.........................

Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016 .............................................................

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

Page

48

49

51

52

53

54

55

47

 
 
Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors
El Paso Electric Company:

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying balance sheets of El Paso Electric Company (the "Company") as of December 31, 2018 and 
2017, 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, 2018, and the related notes (collectively, the "financial statements"). We 
also have audited the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in 
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company 
as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period 
ended December 31, 2018, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company 
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria 
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway 
Commission.

Basis for Opinions

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

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

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

Definition and Limitations of Internal Control over Financial Reporting

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

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

/s/ KPMG LLP

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

Houston, Texas
February 28, 2019

48

EL PASO ELECTRIC COMPANY 
BALANCE SHEETS

Utility plant:

ASSETS
(In thousands)

December 31,

2018

2017

Electric plant in service ........................................................................................................... $ 4,181,409
(1,391,266)
Less accumulated depreciation and amortization....................................................................
2,790,143
Net plant in service...........................................................................................................
169,327
Construction work in progress.................................................................................................

$ 3,982,095
(1,320,175)
2,661,920
146,059

Nuclear fuel; includes fuel in process of $62,833 and $59,689, respectively .........................
Less accumulated amortization ...............................................................................................
Net nuclear fuel ................................................................................................................
Net utility plant .......................................................................................................

198,280
(72,703)
125,577

194,933
(74,475)
120,458

3,085,047

2,928,437

Current assets:

Cash and cash equivalents .......................................................................................................
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,070
and $2,300, respectively ..........................................................................................................
Inventories, at cost...................................................................................................................
Regulatory assets .....................................................................................................................
Prepayments and other ............................................................................................................
Total current assets .................................................................................................

Deferred charges and other assets:

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

369,921
Total assets...................................................................................................... $ 3,628,502

12,900

77,855

55,432

6,972

20,375

173,534

276,905

74,848

18,168

6,990

88,585

50,910

—

10,307

156,792

286,866

96,036

16,232

399,134

$ 3,484,363

See accompanying notes to financial statements.

49

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, 65,707,156 and
65,694,829 shares issued, and 121,532 and 133,859 restricted shares, respectively .............. $
Capital in excess of stated value..............................................................................................
Retained earnings ....................................................................................................................
Accumulated other comprehensive income (loss), net of tax..................................................

Treasury stock, 25,147,567 and 25,244,350 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........................................................................................................................
Regulatory liabilities ...............................................................................................................
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,

2018

2017

$

65,829
328,480
1,227,471
(38,784)
1,582,996
(418,893)
1,164,103
1,285,980
2,450,083

65,829
326,117
1,159,667
11,058
1,562,671
(420,506)
1,142,165
1,195,988
2,338,153

99,239
49,207
58,150
37,139
16,478
14,686
38,356
313,255

325,133
87,259
24,575
101,108
298,570
28,519
865,164

—
173,533
59,270
35,660
12,470
6,225
29,067
316,225

305,023
83,838
26,417
93,029
296,685
24,993
829,985

Total capitalization and liabilities ................................................................ $ 3,628,502

$ 3,484,363

See accompanying notes to financial statements.

50

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

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

Fuel and purchased power .............................................................................

Operations and 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.

Years Ended December 31,

2018

2017

2016

903,603

$

916,797

$

886,936

229,109

334,883

96,382

71,000

731,374

172,229

3,453

18,377

12,823
(11,980)
22,673

75,424

17,890
(5,483)
(3,612)
84,219

110,683

26,368

84,315

2.07

2.07

1.415

$

$

$

$

244,751

320,281

90,843

70,863

726,738

190,059

3,025

38,853

12,051
(11,580)
42,349

72,970

18,170
(5,022)
(2,975)
83,143

149,265

51,004

98,261

2.42

2.42

1.315

$

$

$

$

233,465

315,710

84,317

65,533

699,025

187,911

7,023

34,797

11,073
(11,038)
41,855

71,544

17,509
(4,990)
(4,983)
79,080

150,686

53,918

96,768

2.39

2.39

1.225

40,521,364

40,414,556

40,350,688

40,642,640

40,535,191

40,408,033

51

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,

2018

2017

2016

84,315

$

98,261

$

96,768

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

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

Reclassification adjustments included in net income for amortization of:
Prior service benefit ..........................................................................

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

(5,898)
—

(9,657)
6,387

12,634

—

(20,053)
32,697

(9,657)
6,776

(7,407)
4,965

Net unrealized gains/losses on marketable securities:

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

(4,072)

25,275

8,444

Reclassification adjustments for net (gains) losses included in net
income.........................................................................................................

1,445

(10,626)

(7,640)

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

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

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

568
(11,227)

532

24,934

498

11,504

2,035

523
(145)
2,413
(8,814)
75,501

(3,615)
(2,922)
(223)
(6,760)
18,174

(4,261)
(106)
(339)
(4,706)
6,798

$

116,435

$

103,566

See accompanying notes to financial statements.

52

5
3

S
e
e

a
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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 losses (gains) on decommissioning trust funds ...................................................
Other operating activities ..........................................................................................

Change in:

Accounts receivable ...................................................................................................
Inventories .................................................................................................................
Prepayments and other ..............................................................................................
Accounts payable ......................................................................................................
Taxes accrued ............................................................................................................
Interest accrued ..........................................................................................................
Net over-collection (under-collection) of fuel revenues ............................................
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 ............................................................................................
Insurance proceeds received for equipment .......................................................................
Capitalized interest and AFUDC:

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

Decommissioning trust funds:

Purchases, including funding of $2.1 million, $3.8 million and $4.5 million,
respectively ................................................................................................................
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 ...................................................................................................................
Proceeds from issuance of senior notes .............................................................................
Proceeds from issuance of RGRT senior notes ..................................................................

Payments on maturing RGRT senior notes ........................................................................
Payments on maturing pollution control bonds ..................................................................
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,
2017

2016

2018

84,315

$

98,261

$

96,768

96,382
38,176
29,118
(3,453)

20,830
—
12,967
(38)

5,712
(4,117)
(4,419)
(2,233)
(5,487)
4,008
4,822
9,289
(475)
285,397

(240,021)
(38,354)
5,351

(7,065)
(5,483)
3,453

(86,366)

80,732
287
4,186
(283,280)

90,843
42,476
49,394
(3,025)

18,954
—
(10,626)
(692)

(138)
(3,073)
(692)
1,407
1,840
(817)
17,093
(100)
(12,544)
288,561

(199,896)
(38,481)
9,591

(6,000)
(5,022)
3,025

(102,920)

97,037
281
(1,559)
(243,944)

84,317
43,748
50,510
(7,023)

17,295
(545)
(7,640)
1,279

(17,511)
265
(1,184)
(2,140)
1,945
638
(14,891)
1,384
(16,065)
231,150

(229,722)
(42,383)
4,361

(12,006)
(4,990)
7,023

(99,497)

91,268
4,841
5,373
(275,732)

(57,539)

(53,337)

(49,603)

567,894
(692,220)

125,000
65,000

—

—
(4,342)
3,793

5,910

6,990

638,458
(546,499)

—
—

(50,000)

(33,300)
(1,369)
(46,047)

(1,430)

8,420

355,607
(415,771)

157,052
—

—

—
(2,432)
44,853

271

8,149

8,420

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

12,900

$

6,990

$

See accompanying notes to financial statements.

54

INDEX TO NOTES TO FINANCIAL STATEMENTS

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

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

Note C. Revenues ...................................................................................................................................................................

Note D. Regulation .................................................................................................................................................................

Note E. Regulatory Assets and Liabilities ..............................................................................................................................

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

Note G. Accounting for Asset Retirement Obligations ..........................................................................................................

Note H. Common Stock..........................................................................................................................................................

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

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

Note K. Income Taxes ............................................................................................................................................................

Note L. Commitments, Contingencies and Uncertainties ......................................................................................................

Note M. Litigation ..................................................................................................................................................................

Note N. Employee Benefits ....................................................................................................................................................

Page
56

60

62

63

70

72

75

76

81

83

86

89

91

92

Note O. Franchises and Significant Customers ......................................................................................................................

105

Note P. Financial Instruments and Investments......................................................................................................................

106

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

111

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

112

55

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

A.

Summary of Significant Accounting Policies

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.

Basis of Presentation. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed 

by the Federal Energy Regulatory Commission ("FERC").

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

Application of the Financial Accounting Standards Board ("FASB") Guidance for Regulated Operations. Regulated electric 
utilities typically prepare their financial statements in accordance with the FASB guidance for regulated operations. The FASB 
guidance  for  regulated  operations  requires  the  Company  to  include  an  allowance  for  equity  and  borrowed  funds  used  during 
construction ("AEFUDC" and "ABFUDC") as a cost of construction of electric plant in service. AEFUDC is recognized as income, 
and ABFUDC is shown as capitalized interest charges in the Company’s statements of operations. The FASB guidance for regulated 
operations also requires the Company to show certain 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 E of Notes to Financial Statements for further discussion. 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 2018, 2017 and 2016 was 2.28%, 2.27% and 2.28%, 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, if applicable.

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

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

Allowance for Funds Used During Construction ("AFUDC") and Capitalized Interest. The Company capitalizes interest 
(ABFUDC) and common equity (AEFUDC) costs to construction work in progress ("CWIP") and capitalizes interest to nuclear 
fuel in process in accordance with the FERC Uniform System of Accounts as provided for in the FASB guidance. AFUDC is a 
non-cash component of income and is calculated monthly and charged to all new eligible construction and capital improvement 
projects. AFUDC is compounded on a semi-annual basis. The average AFUDC rates used in 2018, 2017 and 2016 were 5.95%, 
5.38% and 6.43%, respectively.

56

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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 G of Notes to Financial Statements for further discussion. 
Under the FASB guidance, these liabilities are recognized as incurred if a reasonable estimate of fair value can be established and 
are capitalized as part of the cost of the related tangible long-lived assets. The Company records the increase in the ARO due to 
the passage of time as an operating expense (accretion expense).

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

Investments. The Company’s marketable securities, included in the NDT on the balance sheet, are reported at fair value and 
consist of cash, equity securities and debt securities held in the NDT. Investments in equity securities are measured at fair market 
value. Changes in fair value for equity securities are recognized in the statement of operations. Debt securities are classified as 
"available-for-sale" securities and, as such, unrealized gains and losses are included in accumulated other comprehensive loss as 
a separate component of common stock equity. However, if declines in the fair value of debt securities below original cost basis 
are determined to be other than temporary, the declines are reported as losses in the statements of operations and a new cost basis 
is established for the affected securities at fair value. Gains and losses are determined using the cost of the security based on the 
specific identification basis. See Part II, Item 8, Financial Statements and Supplementary Data, Note P of Notes to Financial 
Statements for further discussion.

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 P of Notes to Financial Statements for further discussion.

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

to exceed recoverable cost.

Operating Revenues. The Company accrues revenues for services rendered, including unbilled electric service revenues. 
Fuel and purchase power expenses are stated at actual cost incurred. The Company recognizes revenue associated with contracts 
with customers when performance obligations under the terms of the contract with the customer are satisfied. Revenue is measured 
as the amount of consideration the Company receives in exchange for transferring goods or providing services to the customer. 
Taxes collected concurrently with revenue producing activities are excluded from revenue. Unbilled revenues are recorded for 
estimated amounts of energy delivered in the period following the customer's last billing cycle to the end of the reporting period. 
Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kilowatt-hour ("kWh") 
to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $21.6 million
and  $22.2  million  as  of  December 31,  2018  and  2017,  respectively. The  Company  presents  revenues  net  of  sales  taxes  in  its 
statements of operations. 

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 that 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 that is adjusted 
monthly. The Company’s recovery of fuel and purchased power expenses is subject to periodic reconciliations of actual fuel and 
purchased power expenses incurred to actual fuel revenues collected. The difference between fuel and purchased power expenses 
incurred  and  fuel  revenues  charged  to  customers  is  reflected  as  over/under-collection  of  fuel  revenues,  which  is  included  in 
regulatory liabilities/assets - current in the balance sheets. See Part II, Item 8, Financial Statements and Supplementary Data, Note 
D of Notes to Financial Statements for further discussion.

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 

57

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

environment. Additions, deductions and balances for allowance for doubtful accounts for 2018, 2017 and 2016 are as follows (in 
thousands):

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

2018

2017

2016

2,300

$

2,156

$

2,046

2,855
1,215
4,300
2,070

$

3,141
1,122
4,119
2,300

$

2,427
1,395
3,712
2,156

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, 
unless those deferred taxes will be collected from or returned to customers in which case they are recorded as a regulatory asset 
or liability. See Part II, Item 8, Financial Statements and Supplementary Data, Note K of Notes to Financial Statements for further 
discussion. 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 K of Notes to Financial Statements.

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

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

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

58

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

diluted  earnings  per  share.  See  Part  II,  Item  8,  Financial  Statements  and  Supplementary  Data,  Note H  of  Notes  to  Financial 
Statements for further discussion.

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  (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 H of Notes to Financial Statements for further discussion.

Pension and Post-retirement Benefit Accounting. See Part II, Item 8, Financial Statements and Supplementary Data, Note N 

of Notes to Financial Statements for a discussion of the Company's accounting policies for its employee benefits. 

Reclassification. Certain amounts in the financial statements for 2017 and 2016 have been reclassified to conform to the 
2018  presentation. The  Company  implemented Accounting  Standards  Update  ("ASU")  2017-07,  Compensation  -  Retirement 
Benefits, and ASU 2016-15, Statement of Cash Flows, in the first quarter of 2018, retrospectively to all periods presented in the 
Company's financial statements. See Part II, Item 8, Financial Statements and Supplementary Data, Note B of Notes to Financial 
Statements for further discussion on the new accounting standards.

59

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

B.

New Accounting Standards

New Accounting Standards Adopted

In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718) Improvements to Employee 
Share-Based Payment Accounting, to simplify the accounting for share-based payment transactions, including the income tax 
consequences, classification of awards either as equity or liabilities, and classification on the statements of cash flows. The Company 
adopted the new standard effective January 1, 2017. The adoption of the new standard did not have a material impact on the 
Company's financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard was 
to increase net operating loss carryforward ("NOL carryforward") deferred tax assets and retained earnings by $0.2 million on 
January 1, 2017. 

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), to provide a framework 
that replaced the prior revenue recognition guidance, and FASB has since modified the standard with several ASUs. The standard 
provides that an entity should recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods 
or services to customers. On January 1, 2018, the Company adopted the new accounting standard using the modified retrospective 
method.  There  was  no  cumulative  effect  adjustment  at  the  initial  application  of  the  new  standard.  In  addition,  comparative 
information has not been restated and continues to be reported under the accounting standards in effect for those periods. The 
Company expects the ongoing impact of the new standard to be immaterial to net income. Following the adoption of the standard, 
revenues of $8.9 million related to reimbursed costs of energy efficiency programs approved by the Company's regulators are 
reported in operating revenues from customers prospectively, as opposed to being offset with associated costs within operations 
and maintenance ("O&M") expenses. Related expenses of an equal amount are reported in O&M expenses. See Part II, Item 8, 
Financial Statements and Supplementary Data, Note C of Notes to Financial Statements for further discussion on revenues. 

In  January  2016,  the  FASB  issued ASU  2016-01,  Financial  Instruments  -  Overall  (Subtopic  825-10):  Recognition  and 
Measurement of Financial Assets and Financial Liabilities, to enhance the reporting model for financial instruments by addressing 
certain aspects of recognition, measurement, presentation and disclosure. The Company adopted the new standard effective January 
1,  2018. The  adoption  of ASU  2016-01  eliminates  the  requirements  to  classify  investments  in  equity  securities  with  readily 
determinable fair values into trading or available for sale and requires entities to measure equity investments at fair value and 
recognize any changes in fair value in the Statements of Operations. ASU 2016-01 requires a modified retrospective approach and 
therefore comparative information has not been restated and continues to be reported under the accounting standards in effect for 
those periods. Upon adoption of the new standard, the Company recorded a cumulative effect adjustment, net of income taxes to 
increase retained earnings by $41.0 million with a corresponding decrease to accumulated other comprehensive income ("AOCI"). 
In addition, the Company recorded net losses of $18.6 million related to equity securities still held at December 31, 2018. In March 
2018, the FASB issued ASU 2018-04, Investments - Debt Securities (Topic 320) and Regulated Operations (Topic 980), which 
provides clarification to ASU 2016-01. 

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts 
and Cash Payments, to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement 
of cash flows. The Company adopted the new standard effective January 1, 2018. ASU 2016-15 was applied using a retrospective 
transition method to each period presented. Accordingly, the Company presented in the Statement of Cash Flows insurance proceeds 
received for equipment of $5.4 million, $9.6 million and $4.4 million, respectively, for the twelve months ended December 31, 
2018, 2017 and 2016 as cash inflows from investing activities. 

In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits (Topic 715) Improving the Presentation 
of  Net  Periodic  Pension  Cost  and  Net  Periodic  Postretirement  Benefit  Cost.  ASU  2017-07  amends  Accounting  Standards 
Codification ("ASC") 715, Compensation - Retirement Benefits, to require companies to present the service cost component of 
net benefit cost in the income statement line items where compensation cost is reported. Companies will present all other components 
of net benefit cost separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. 
In addition, only the service cost component will be eligible for capitalization in assets. The Company adopted the new standard 
effective January 1, 2018. The amendments in ASU 2017-07 were applied retrospectively for the income statement presentation 
of the service cost component and the other components of net benefit costs. The Company elected to apply the practical expedient 
and used the amounts disclosed in the pension and other postretirement benefit plan note for the 2017 and 2016 comparative periods 
as the estimation basis for applying the retrospective presentation requirements. See Part II, Item 8, Financial Statements and 
Supplementary Data, Note N of Notes to Financial Statements for further discussion on employee benefits.

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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

In March 2018, the FASB issued ASU 2018-05, Income Taxes (Topic 740) Amendments to U.S. Securities and Exchange 
Commission ("SEC") Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118"), to add various SEC paragraphs 
for clarification due to the TCJA. The Company adopted ASU 2018-05 upon issuance and implemented SAB 118 in December 
of 2017 in conjunction with the enactment of the TCJA. 

In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud 
Computing  Arrangement  That  Is  a  Service  Contract  (Topic  350).  ASU  2018-15  aligns  the  requirements  for  capitalizing 
implementation costs for a cloud computing arrangement with the requirements for capitalizing implementation costs for an internal 
use software license. Implementation costs for a cloud computing arrangement will be capitalized or expensed based on the nature 
of  the  costs  and  the  project’s  stage  in  which  they  are  incurred  by  applying  the  existing  guidance  for  internal  use  software 
implementation costs. Capitalized costs for a cloud computing arrangement will be presented on the same line of the balance sheet 
as any related prepaid amounts for the arrangement, while amortization of those costs will be presented on the same line of the 
income statement as the related hosting fees. Early adoption is permitted, and entities may apply the guidance either prospectively 
to eligible costs incurred on or after the effective date or retrospectively. The Company early-adopted this guidance in the third 
quarter of 2018, on a prospective basis, and the adoption did not have a material impact on the Company’s financial condition, 
results of operations or cash flows. 

New Accounting Standards to be Adopted in the Future

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), to increase transparency and comparability among 
organizations  by  recognizing  lease  assets  and  lease  liabilities  on  the  balance  sheet  and  requiring  qualitative  and  quantitative 
disclosures on leasing agreements. ASU 2016-02 maintains a distinction between finance leases and operating leases similar to 
the distinction under previous lease guidance for capital leases and operating leases. The impact of leases reported in the Company's 
operating results and statement of cash flows is expected to be similar to previous GAAP. ASU 2016-02 requires the recognition 
in the statement of financial position, by the lessee, of a liability to make lease payments (the lease liability) and a right-of-use 
asset representing its right to use the underlying asset for the lease term. How operating leases are recorded in regard to the 
Company's balance sheet represents a significant change from previous GAAP guidance. The lessee is permitted to make an 
accounting  policy  election  to  not  recognize  lease  assets  and  lease  liabilities  for  short-term  leases. Adoption  of  the  new  lease 
accounting standard will require the Company to apply the new standard to the earliest period using a modified retrospective 
approach. As part of an effort to minimize adoption impact from the new standard, the FASB issued ASU 2018-01 and 2018-11. 
ASU 2018-01 provides an optional practical expedient to not evaluate existing or expired land easements under Topic 842, if those 
land easements were not previously accounted for as leases under ASC Topic 840, while ASU 2018-11 allows entities to adopt 
the standard with a cumulative effect adjustment as of the beginning of the adoption year, while maintaining prior year comparative 
financial information and disclosures as reported. As part of its application of ASU 2016-02, the Company has completed its 
analysis of its lease population and is finalizing the implementation of a new lease accounting system, as well as the evaluation 
of the impact on business processes, systems and controls to support recognition and disclosure under the new guidance. The 
Company anticipates it will elect the following practical expedients: the package of practical expedients outlined in ASU 2016-02, 
the land easement practical expedient outlined in ASU 2018-01, and the optional transition expedient outlined in ASU 2018-11. 
The Company also anticipates making the accounting policy election to not apply balance sheet recognition to short term leases. 
The Company will adopt this guidance effective January 1, 2019 and the adoption will only affect the balance sheet by recording 
lease obligations and corresponding right of use assets in an amount that ranges between $5.0 million and $8.0 million. 

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

In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), as a 
result of concerns raised due to the TCJA. More specifically, because the remeasurement of deferred taxes due to the change in 
the federal corporate income tax rate is required to be included in income from continuing operations, the tax effects of items 
within AOCI (referred to as stranded tax effects) do not reflect the appropriate tax rate. ASU 2018-02 generally allows companies 
to reclassify stranded taxes from AOCI to retained earnings. The amount of the adjustment would be the difference between the 
historical federal corporate income tax rate of 35% and the newly enacted 21% federal corporate income tax rate. The provisions 

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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

of ASU 2018-02 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2018. 
Early adoption is permitted, including adoption in any interim periods for reporting periods for which financial statements have 
not been issued. The Company is currently evaluating the impact of ASU 2018-02 and its impact on regulated utilities. At December 
31, 2018, stranded taxes in AOCI are approximately $7.2 million. The Company currently does not believe the adoption of this 
ASU will have a material impact on its financial condition, results of operations, or cash flows. 

C.

Revenues

On January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), for all of 
its contracts using the modified retrospective method. There was no cumulative effect adjustment at the initial application of the 
new  standard.  In  addition,  comparative  information  has  not  been  restated  and  continues  to  be  reported  under  the  accounting 
standards in effect for those periods. The Company expects the ongoing impact of the new standard to be immaterial to net income 
and no significant changes in the Company's business processes and internal controls were necessary upon adoption of the new 
standard.

The following table disaggregates revenue from contracts with customers, for the twelve months ended December 31, 2018

(in thousands):

December 31, 2018

Twelve Months 
Ended

Retail.................................................................................... $
Wholesale ............................................................................
Wheeling (transmission)......................................................
Total revenues from contracts with customers..................
Other ....................................................................................

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

789,676

90,673

19,026

899,375

4,228

903,603

The  Company  recognizes  revenue  when  performance obligations  under  the  terms  of  the  contract  with  the  customer are 
satisfied. Revenue is measured as the amount of consideration the Company receives in exchange for transferring goods or providing 
services to the customer. Taxes collected concurrently with revenue producing activities are excluded from revenue. The Company 
has elected the optional invoice practical expedient for Wholesale and Wheeling revenues, as the invoice amount will correspond 
directly to the value provided by the Company's performance to date.

Retail. Retail contracts represent the Company's primary revenue source. The Company has determined that retail electric 
service to residential, commercial and industrial, and public authority customers represents an implied daily contract with the 
customer. The contract is comprised of an obligation to supply and distribute electricity and related capacity. Revenue is recognized, 
over time, equal to the product of the applicable tariff rates, as approved by the PUCT and the NMPRC, and the volume of the 
electricity delivered to the customer, or through the passage of time based upon providing the service of standing ready. Unbilled 
revenues are recognized at month end based on estimated monthly generation volumes and by applying an average revenue per 
kWh to the number of estimated kWhs delivered but not billed to customers, and recorded as a receivable for the period following 
the last billing cycle to the end of the reporting period. Retail customers receive a bill monthly, with payment due sixteen days 
after issuance.

Wholesale. Wholesale contracts primarily include forward power sales into markets outside the Company’s service territory 
when the Company has competitive generation capacity available, after meeting its regulated service obligations. Pricing is either 
fixed or based on an index rate with consideration potentially including variable components. Uncertainties regarding the variable 
consideration will be resolved when the transaction price is known at the point of delivering the energy. The obligation to deliver 
the electricity is satisfied over time as the customer receives and consumes the electricity. Wholesale customers are invoiced 
monthly on the 10th day of each month, with payment due by the 20th day of the month. In the case of the sale of renewable energy 
certificates, the transaction price is allocated to the performance obligation to deliver the confirmed quantity of the certificates 
based on the stand alone selling price of each certificate. Revenue is recognized as control of the certificates is transferred to the 
customer. The customer is invoiced upon the completed transfer of the certificates, with payment due within ten business days.
Wholesale also includes an annual agreement between the Company and one of its wholesale customers, Rio Grande Electric 

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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Cooperative ("RGEC"), which involves the provision of full requirements electric service from the Company to RGEC. The rates 
for this service are recalculated annually and require FERC approval.

Wheeling (transmission). Wheeling involves the Company providing point-to-point transmission service, which includes the 
receipt of capacity and energy at designated point(s) and the transfer of such capacity and energy to designated point(s) of delivery 
on either a firm or non-firm basis for periods of one year or less. The performance obligation to provide capacity and transmit 
energy is satisfied over time as the Company performs. Transmission customers are invoiced on a monthly basis, with payment 
due within twenty days of receipt of the invoice.

Other. Other includes alternative revenue program revenue relating to the Company’s potential bonus awards from the PUCT 
and the NMPRC mandated energy efficiency programs. Both the PUCT and the NMPRC allow for the potential to earn an incentive 
bonus if the Company achieves its approved energy efficiency goals under the applicable programs. The Company recognizes 
revenue related to the energy efficiency program incentives at the point in time that the amount is objectively determinable generally 
based upon an approved order from the regulator, is probable of recovery, and if it is expected to be collected within 24 months. 
Other revenue also includes (i) late payment fees, (ii) leasing income, and (iii) the Company’s allocated share, based on ownership, 
of sales of surplus effluent water from Palo Verde.

Accounts receivable. Accounts receivable is principally comprised of revenue from contracts with customers. The Company 
recognizes expense for accounts that are deemed uncollectible in operating expense. The Company recognized $2.9 million of 
uncollectible expense for the twelve months ended December 31, 2018.

D.

Regulation

General

The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC and 
the FERC. Municipal orders, ordinances and other agreements regarding rates and services adopted by Texas municipalities are 
subject to review and approval by the PUCT. The FERC has jurisdiction over the Company's wholesale (sales for resale - full 
requirement  customer)  transactions,  transmission  service  and  compliance  with  federally-mandated  reliability  standards.  The 
decisions of the PUCT, the NMPRC and the FERC are subject to judicial review. 

Texas Regulatory Matters

2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities 
incorporated in its Texas service territory and the PUCT in the 2015 Texas Retail Rate Case, a request for an annual increase in 
non-fuel base revenues ("2015 Texas Retail Rate Case"). On July 21, 2016, the parties to PUCT Docket No. 44941 filed the Joint 
Motion to Implement Uncontested Amended and Restated Stipulation and Agreement which was unopposed by the parties. On 
August 25, 2016, the PUCT issued the PUCT Final Order in Docket No. 44941 ("2016 PUCT Final Order"). Interim rates associated 
with the annual non-fuel base rate increase became effective on April 1, 2016. The additional surcharges associated with the 
incremental Four Corners Generating Station ("Four Corners") costs, rate case expenses and the relate back of rates to consumption 
on and after January 12, 2016, through March 31, 2016, were implemented on October 1, 2016. 

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

2017 Texas Retail Rate Case Filing. On February 13, 2017, the Company filed with the City of El Paso, other municipalities 
incorporated in the Company's Texas service territory and the PUCT in the 2017 Texas Retail Rate Case, a request for an increase 
in non-fuel base revenues. On November 2, 2017, the Company filed the Joint Motion to Implement Uncontested Stipulation and 
Agreement with the Administrative Law Judges for the 2017 Texas Retail Rate Case. 

On December 18, 2017, the PUCT issued the PUCT Final Order in Docket No. 46831 ("2017 PUCT Final Order"), which 
provides, among other things, for the following: (i) an annual non-fuel base rate increase of $14.5 million; (ii) a return on equity 
of 9.65%; (iii) all new plant in service as filed in the Company's rate filing package was prudent and used and useful and therefore 
is included in rate base; (iv) recovery of the costs of decommissioning Four Corners in the amount of $5.5 million over a seven

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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

year period beginning August 1, 2017; (v) the Company to recover reasonable rate case expenses of approximately $3.4 million
through a separate surcharge over a three year period; and (vi) a requirement that the Company file a refund tariff if the federal 
statutory income tax rate, as it relates to the Company, is decreased before the Company files its next rate case. The 2017 PUCT 
Final Order also established baseline revenue requirements for recovery of future transmission and distribution investment costs 
(for which the Company could seek recovery after January 1, 2019) and includes a minimum monthly bill of $30.00 for new 
residential customers with distributed generation, such as private rooftop solar. Additionally, the 2017 PUCT Final Order allowed 
for the annual recovery of $2.1 million of nuclear decommissioning funding and establishes annual depreciation expense that is 
approximately $1.9 million lower than the annual amount requested by the Company in its initial filing. Finally, the 2017 PUCT 
Final Order allowed for the Company to recover revenues associated with the relate back of rates to consumption on and after 
July 18, 2017, through a separate surcharge, which expired on January 9, 2019, with a reconciliation of any over- or under-charge 
to be addressed in a separate proceeding. 

New base rates, including additional surcharges associated with rate case expenses and the relate back of rates to consumption 

on and after July 18, 2017, through December 31, 2017, were implemented in January 2018.

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

The 2017 PUCT Final Order required the Company to file a refund tariff if the federal statutory income tax rate, as it 
relates to the Company, was decreased before the Company files its next general rate case. Following the enactment of the 
TCJA on December 22, 2017, and in compliance with the 2017 PUCT Final Order, on March 1, 2018, the Company filed with 
the PUCT and each of its municipalities a proposed refund tariff designed to reduce base charges for Texas customers 
equivalent to the expected annual decrease of $22.7 million in federal income tax expense resulting from the TCJA changes, 
and an additional refund of $4.3 million for the amortization of a regulatory liability related to the reduced tax expense for the 
months of January through March of 2018. This filing was assigned PUCT Docket No. 48124. On March 27, 2018, the PUCT 
approved the Company's proposed refund tariff on an interim basis, subject to refund or surcharge, for customer billing 
effective April 1, 2018. Each of the Company's municipalities also implemented the Company's proposed tax credits on an 
interim basis effective April 1, 2018. The refund is reflected in rates over a period of one year beginning April 1, 2018, and will 
be updated annually until new base rates are implemented pursuant to the Company's next Texas rate case filing. The PUCT 
issued an order on December 10, 2018, approving the proposed refund tariff. 

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

On May 1, 2018, the Company filed its annual application with the PUCT, which was assigned PUCT Docket No. 48332, 
to establish its energy efficiency cost recovery factor for 2019. In addition to projected energy efficiency costs for 2019 and a 
reconciliation of collections to actual costs for the prior year, the Company requested approval of a $1.0 million incentive bonus 
for the 2017 energy efficiency program results in accordance with PUCT rules. Instead of convening an actual hearing on the 
merits of this case, the parties agreed to enter into the record the pre-filed testimony of the parties and certain other exhibits and 
then file briefs on the contested issues. The Administrative Law Judge issued a proposed final decision on November 15, 2018, 
including the Company's fully requested incentive bonus. On January 17, 2019, the PUCT issued an order approving a modified 
bonus amount of $0.9 million.

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 ("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 

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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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 periodic 
fuel reconciliation proceedings. 

On November 30, 2016, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 46610, to 
increase its fixed fuel factor by approximately 28.8% to reflect increased fuel expenses primarily related to an increase in the price 
of natural gas used to generate power. The increase in the fixed fuel factor was effective on an interim basis January 1, 2017, and 
approved by the PUCT on January 10, 2017.

On October 13, 2017, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 47692, to decrease 
the Texas fixed fuel factor by approximately 19% to reflect decreased fuel expenses primarily related to a decrease in the price of 
natural gas used to generate power. The decrease in the Texas fixed fuel factor became effective beginning with the November 
2017 billing month.

On April 13, 2018, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 48264, to decrease 
the Texas fixed fuel factor by approximately 29% to reflect decreased fuel expenses primarily related to a decrease in the price of 
natural gas used to generate power. On April 25, 2018, the Company's proposed fuel factors were approved on an interim basis 
effective for the first billing cycle of the May 2018 billing month. The revised factor was approved by the PUCT and the docket 
closed on May 22, 2018.

On October 15, 2018, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 48781, to decrease 
the Texas fixed fuel factor by approximately 6.99% to reflect decreased fuel expenses primarily related to a decrease in the price 
of natural gas used to generate power. On October 25, 2018, the Company's fixed fuel factor was approved on an interim basis 
effective for the first billing cycle of the November 2018 billing month. The revised factor was approved by the PUCT and the 
docket closed on November 19, 2018. The Texas fixed fuel factor will continue thereafter until changed by the PUCT. As of 
December 31, 2018, the Company had a net fuel over-recovery balance of approximately $8.9 million in Texas. 

Fuel Reconciliation Proceeding. On September 27, 2016, the Company filed an application with the PUCT, designated as 
PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of 
April 1, 2013, through March 31, 2016. On June 29, 2017, the PUCT approved a settlement in this proceeding. The settlement 
provides  for  the  reconciliation of  fuel  and  purchased  power  costs  incurred  from April 1,  2013,  through  March 31,  2016. The 
financial results for the twelve months ended December 31, 2017, includes a $5.0 million, pre-tax increase to income reflecting 
the settlement of the Texas fuel reconciliation proceeding. This amount represents Palo Verde performance rewards associated 
with the 2013 to 2015 performance periods net of disallowed fuel and purchased power costs as approved in the settlement. 
Additionally, the settlement modifies and tightens the Palo Verde performance rewards measurement bands beginning with the 
2018 performance period. The April 1, 2016, through December 31, 2018, Texas jurisdictional fuel and purchased power costs 
subject to prudence review total approximately $353.4 million.

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

On March 20, 2018, the Company filed a petition with the PUCT and each of its Texas municipalities to expand its community 
solar program in Texas to include two-MW of solar powered generation from the ten-MW solar photovoltaic facility located at 
Newman Power Station ("Newman") and to reduce rates under the community solar tariff. The case before the PUCT was assigned 
PUCT Docket No. 48181 and a hearing was held on December 4, 2018. The Company cannot predict the outcome of the case at 
this time.

Transmission Cost Recovery Factor. On January 25, 2019, the Company filed an application with the PUCT to establish its 
Transmission Cost Recovery Factor ("TCRF"), which was assigned PUCT Docket No. 49148 ("2019 TCRF rate filing"). The 2019 
TCRF rate filing is designed to recover a requested $8.2 million of Texas jurisdictional transmission revenue requirement that is 
not currently being recovered in the Company's Texas base rates for transmission-related investments placed in service from 
October 1, 2016, through September 30, 2018, net of retirements. The Company cannot predict the outcome of this filing at this 
time. 

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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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

On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and 
certain rate and accounting findings related to the Purchase and Sale Agreement. This case was assigned PUCT Docket No. 44805. 
Subsequent to the filing of the application, the case was subject to numerous procedural matters, including a March 23, 2016, 
order in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the 
requested rate and accounting findings, including coal mine reclamation costs, in a rate case proceeding. On September 1, 2016, 
a motion by parties in the proceeding to suspend the procedural schedule in order to pursue settlement was approved. On March 3, 
2017, the Company filed a Joint Motion to Implement Stipulation and Agreement ("Stipulation and Agreement"), and PUCT Staff 
filed its recommendation that the Company’s disposition of its interest in Four Corners was reasonable and consistent with the 
public interest. Additionally, the signatories of the Stipulation and Agreement agreed to support the recovery of the Company's 
Four Corners decommissioning costs in the 2017 Texas Retail Rate Case. A final order approving the Stipulation and Agreement 
was adopted by the PUCT on March 30, 2017. The approval to recover Four Corners decommissioning costs was included in the 
2017 PUCT Final Order. 

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

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

New Mexico Regulatory Matters

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

Future New Mexico Rate Case Filing. On April 12, 2017, the NMPRC issued an order in Case No. 15-00109-UT requiring 

the Company to make a rate filing in New Mexico no later than July 31, 2019, using an appropriate historical test year period. 

New Mexico Order Commencing Review of the Effects of the TCJA on Regulated New Mexico Utilities. On January 24, 2018, 
the NMPRC initiated a proceeding in Case No. 18-00016-UT on the impact of the TCJA on New Mexico regulated utilities. On 
February 23, 2018, the Company responded to a NMPRC Staff inquiry regarding the proceeding. On April 4, 2018, the NMPRC 
issued an order requiring the Company to file a proposed interim rate rider to adjust the Company's New Mexico base revenues 
in amounts equivalent to the Company's reduced income tax expense for New Mexico customers resulting from the TCJA, to be 
implemented on or before May 1, 2018. The NMPRC order further requires that the Company record and track a regulatory liability 
for the excess accumulated deferred income taxes created by the change in the federal corporate income tax rate, consistent with 
the effective date of the TCJA, and subject to amortization determined by the NMPRC in the Company's next general rate case. 
The Company recorded such a regulatory liability during the quarter ended December 31, 2017. On April 16, 2018, after consultation 
with the New Mexico Attorney General pursuant to the NMPRC order, the Company filed an interim rate rider with the NMPRC 
with  a  proposed  effective  date  of  May 1,  2018.  The  annualized  credits  expected  to  be  refunded  to  New Mexico  customers 
approximate $4.9 million. The Company implemented the interim rate rider in customer bills beginning May 1, 2018 pursuant to 
the NMPRC order. 

On  September  5,  2018,  the  NMPRC  issued  an  order  in  Case  No. 17-00255-UT  involving  Southwestern  Public  Service 
Company's ("SPS's") request to change rates in which the NMPRC directed SPS to refund the difference in corporate tax rate from 
January 1, 2018, through the effective date of new rates. SPS appealed the NMPRC order to the New Mexico Supreme Court in 
Southwestern  Public  Service  Co.  v.  NMPRC,  No. S-1-SC-37248  ("SPS  Appeal  No.  1"),  challenging  the  refund  as  prohibited 
retroactive ratemaking among other reasons. The New Mexico Supreme Court issued a partial and interim stay of the rates on 
September 26, 2018. On September 12, 2018, the NMPRC in Case No. 18-00016-UT issued an Order Regarding the Disposition 
of Tax Savings Under the Federal Tax Cuts and Jobs Act of 2017, which put public utilities on notice that all revenue collected 
through general rates for the purpose of payment of federal income taxes is and will continue to be subject to possible refund upon 
a subsequent determination to be made in the appropriate pending or future NMPRC adjudicatory hearing. On October 11, 2018, 
SPS filed a Notice of Appeal of that NMPRC order to the New Mexico Supreme Court in Southwestern Public Service Co. v. 

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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

NMPRC, No. S-1-SC-37308 ("SPS Appeal No. 2"). Opening briefs in SPS Appeal No. 1 were filed January 14, 2019. In the event 
the NMPRC order in Case No. 17-00255-UT is upheld by the New Mexico Supreme Court, the Company would likely be required 
to record and refund approximately $1.2 million to its New Mexico customers, which represents tax benefits received by the 
Company for the period January 1, 2018, through April 30, 2018. On February 15, 2019, the NMPRC and SPS filed a joint motion 
for remand and stipulated dismissal of SPS appeals of NMPRC orders with the New Mexico Supreme Court, which among other 
things, reflects agreements between the NMPRC and SPS, which in part provide, that the NMPRC will replace the order in Case 
No. 17-00255-UT with a new order that eliminates the retroactive TCJA refund and that SPS will dismiss Appeals No. 1 and No. 
2. The Company is monitoring the SPS cases and cannot determine the outcome of the cases at this time.

Fuel and Purchased Power Costs. Historically, fuel and purchased power costs were recovered through base rates and a Fuel 
and Purchased Power Cost Adjustment Clause ("FPPCAC") that accounts for changes in the costs of fuel relative to the amount 
included in base rates. Effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power 
costs are no longer recovered through base rates but are recovered through the FPPCAC. The Company's request to reconcile its 
fuel and purchased power costs for the period January 1, 2013, through December 31, 2014, also was approved in the NMPRC 
Final Order. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015, through December 31, 
2018, that total approximately $206.8 million. At December 31, 2018, the Company had a net fuel over-recovery balance of 
approximately $0.4 million related to the FPPCAC in New Mexico. As required, the Company filed a request to continue use of 
its FPPCAC with the NMPRC on January 5, 2018, which was assigned Case No. 18-00006-UT. The NMPRC issued a final order 
in the case on February 13, 2019, which authorized the Company to continue use of its FPPCAC without change and approved 
the Company's reconciliation of its fuel and purchased power costs for the period January 1, 2015, through December 31, 2016. 
The final order is subject to rehearing and appeal for thirty days after the February 13, 2019 date of issuance. The Company cannot 
predict the outcome of this case at this time. 

Effective January 1, 2018, pursuant to the final order in NMPRC Case No. 17-00090-UT, the Renewable Portfolio Standard 
("RPS") costs for New Mexico are recovered through a separate RPS Cost Rider and not through the FPPCAC. At December 31, 
2018, the Company had a net fuel over-recovery balance related to the RPS Cost Rider of approximately $1.6 million. The RPS 
Cost Rider is updated in an annual NMPRC filing, including a reconciliation of the prior calendar year’s RPS costs and RPS Cost 
Rider revenue. 

5-MW Holloman Air Force Base ("HAFB") Facility Certificate of Convenience and Necessity ("CCN"). On October 7, 2015,
in Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a five-MW solar power generation facility located 
on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a retail contract, which includes 
a power sales agreement for the facility, to replace the existing load retention agreement that was approved by NMPRC final order 
issued October 5, 2016, in Case No. 16-00224-UT. The solar generation facility began commercial operation on October 18, 2018.

New Mexico Efficient Use of Energy Recovery Factor. On July 1, 2016, the Company filed its annual application with the 
NMPRC requesting approval of its 2017 Energy Efficiency and Load Management Plan and to establish the Efficient Use of 
Energy recovery factor ("EUERF") for 2017. In addition to projected energy efficiency costs for 2017, the Company requested 
approval of a $0.4 million incentive for 2017 energy efficiency programs in accordance with NMPRC rules. This application was 
assigned Case No. 16-00185-UT. On February 22, 2017, the NMPRC issued a final order approving the Company’s 2017 Energy 
Efficiency  and  Load  Management  Plan. The  Company’s  EUERF  was  approved  and  effective  in  customer  bills  beginning  on 
March 1,  2017.  NMPRC  rules  authorize  continuation  of  the  energy  efficiency  programs  and  incentive  approved  in  Case 
No. 16-00185-UT through 2018. The Company recorded approved incentives in operating revenues of $0.3 million and $0.7 
million in 2018 and 2017, respectively, related to its 2015 through 2017 Energy Efficiency and Load Management Plans. 

On July 2, 2018, the Company filed its required application with the NMPRC for approval of its 2019-2021 Energy Efficiency 
and Load Management Plan and EUERF. The application includes a request for a base incentive of 7.1% of program expenditures, 
or approximately $0.4 million annually for 2019-2021. The application was assigned Case No. 18-00116-UT and hearings were 
held on November 7, 2018, and November 8, 2018. The Hearing Examiner issued a Recommended Decision on January 30, 2019, 
and a final order from the NMPRC is pending. The Company cannot predict the outcome of this case at this time. 

Community Solar. On April 24, 2018, the Company filed an application with the NMPRC to initiate a community solar 
program in New Mexico to include construction and ownership of a two-MW solar photovoltaic system located in Doña Ana 
County near the City of Las Cruces. Customer participation would have been on a voluntary basis, and customers would have 
contracted for a set capacity (kW) amount and would have received all energy produced by their subscribed capacity. The application 
was assigned Case No. 18-00099-UT and was dismissed without prejudice on October 31, 2018. The NMPRC set aside its October 
31, 2018, order dismissing the application without prejudice, and on December 19, 2018, the NMPRC issued an Order Requiring 

67

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

El Paso Electric Company to Conduct Request for Proposals and to Amend Application; Order Extending Statutory Period and 
Appointing Hearing Examiner that would have required the Company to amend its initially-filed application on or before February 
15, 2019. However, on January 10, 2019, the NMPRC (with three new Commissioners) reconsidered its prior order and dismissed 
the Community Solar application without prejudice. The case is now closed. 

Integrated Resource Plan. On September 17, 2018, the Company filed its Integrated Resource Plan with the NMPRC for 
the period 2018-2037 ("2018 IRP") in Case No. 18-00293-UT as required by regulation and the Joint Stipulation in NMPRC Case 
No. 15-00241-UT, which was the Company's prior integrated resource plan filing. The triennial filing requires a public advisory 
process as part of the development of the plan to identify a cost-effective portfolio of resources. The filed plan is subject to written 
public comments filed with the NMPRC to which the Company responded on October 29, 2018. NMPRC Staff filed a written 
report on November 16, 2018, recommending that the NMPRC return the 2018 IRP to the Company with instructions for re-filing 
to correct 12 deficiencies identified by the NMPRC Staff report. On December 5, 2018, the NMPRC issued an Order Partially 
Accepting Integrated Resource Plan; Order Requiring Refiling for Deficiencies. Pursuant to that order, on January 3, 2019, the 
Company filed an amended 2018 IRP. On January 10, 2019, in light of a pending motion for reconsideration, the NMPRC ordered 
its Staff to provide additional information and respond to issues raised regarding the filed 2018 IRP. The Company cannot predict 
the outcome of the NMPRC's review of the plan or the outcome of this case at this time. 

Issuance of Long-Term Debt, Securities Financing, and Guarantee of Debt. On October 7, 2015, the Company received 
approval in NMPRC Case No. 15-00280-UT to guarantee the issuance of up to $65.0 million of long-term debt by the Rio Grande 
Resources Trust II ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations, 
which remains effective. Under this authorization, on June 28, 2018, the RGRT issued $65.0 million in aggregate principal amount 
of  4.07%  Senior  Guaranteed  Notes  due August 15,  2025.  On  October  4,  2017,  the  Company  received  additional  approval  in 
NMPRC Case No. 17-00217-UT to amend and extend the Company's Revolving Credit Facility ("RCF"), issue up to $350.0 
million in long-term debt and to redeem and refinance the $63.5 million 2009 Series A 7.25% Pollution Control Bonds ("PCBs") 
and the $37.1 million 2009 Series B 7.25% PCBs, which have optional redemptions beginning in 2019. The NMPRC approval to 
issue $350.0 million in long-term debt supersedes its prior approval. Under this authorization, on June 28, 2018, the Company 
issued $125.0 million in aggregate principal amount of the Company's 4.22% Senior Notes due August 15, 2028. Additionally, on 
September 13, 2018, the Company and the Bank of New York Mellon Trust Company, N.A., as trustee of the RGRT, entered into 
a $350.0 million third amended and restated credit agreement. See Part II, Item 8, Financial Statements and Supplementary Data, 
Note J of Notes to Financial Statements for further discussion on long-term debt and financing obligations. 

On January 30, 2019, the Company submitted an application with the NMPRC seeking approval to issue shares of common 
stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more transactions. The application 
was assigned Case No. 19-00033-UT, and a hearing is scheduled for March 15, 2019. Additionally, the Company is preparing for 
potential transactions related to the 2009 Series A and Series B PCBs. On February 1, 2019, the Company purchased in lieu of 
redemption all the $63.5 million 2009 Series A 7.25% PCBs. The bonds were purchased utilizing funds borrowed under the RCF. 
The Company is currently holding the bonds and may remarket them or replace them with debt instruments of equivalent value 
at a future date depending on the Company's financing needs and market conditions. 

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

by the New Mexico Public Utility Act and the NMPRC. 

Federal Regulatory Matters

Inquiry Regarding the Effect of the TCJA on Commission-Jurisdictional Rates and Order to Show Cause. On March 15, 
2018, the FERC issued two show cause orders under Section 206 of the Federal Power Act and Rule 209(a) of the FERC’s Rules 
of Practice and Procedure, directing 48 individual public utilities with stated transmission rates or transmission formula rates with 
a fixed line item of 35% for the federal income tax component to, within 60 days of the date of the orders, either (1) propose 
revisions to their transmission rates under their open access transmission tariffs or transmission owner tariffs on file with the FERC, 
or (2) show cause why they should not be required to do so ("Show Cause Proceeding"). The Company was included in the list 
of public utilities impacted by the FERC orders. On May 14, 2018, the Company submitted its response, as required by the FERC 
order, which demonstrated that the reduced annual income tax does not cause the Company's total transmission revenues to become 
excessive and therefore no rate reduction was justified. Instead, the Company stated in its response that it will prepare for a future 
filing in which it will seek approval for revised Open Access Transmission Tariff ("OATT") rates that would include the recovery 
of an increased total transmission revenue requirement from OATT customers based on current circumstances and appropriate 
forward-looking adjustments. On November 15, 2018, FERC issued an order finding that the Company had demonstrated that no 

68

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

rate reduction was justified and terminating the Show Cause Proceeding. The Company expects to file its request for approval to 
revise OATT rates in the third quarter of 2019. 

Notice of Proposed Rulemaking on Public Utility Transmission Changes to Address Accumulated Deferred Income Taxes. 
On November 15, 2018, the FERC issued a Notice of Proposed Rulemaking ("NOPR") that proposes to direct public utilities with 
transmission OATT rates, a transmission owner tariff or a rate schedule to determine the amount of excess or deficient accumulated 
deferred income taxes caused by the TCJA’s reduction to the federal corporate income tax rate and return or recover this amount 
to or from customers. The NOPR has been assigned FERC Docket No. RM19-5-000. The Company is currently evaluating the 
impact of this proposed rulemaking. 

Issuance of Long-Term Debt, Securities Financing, and Guarantee of Debt. On October 31, 2017, the FERC issued an order 
in Docket No. ES17-54-000 approving the Company’s filing to (i) amend and extend the RCF; (ii) issue up to $350.0 million in 
long-term debt; (iii) guarantee the issuance of up to $65.0 million of long-term debt by the RGRT; and (iv) redeem, refinance and/
or replace the $63.5 million 2009 Series A 7.25% PCBs and the $37.1 million 2009 Series B 7.25% PCBs, which have optional 
redemptions beginning in 2019. The order also approved the Company's request to continue to utilize the existing RCF with the 
ability to amend and extend at a future date. The authorization is effective from November 15, 2017, through November 14, 2019, 
and supersedes prior FERC approvals. Under this authorization, on June 28, 2018, the Company issued $125.0 million in aggregate 
principal amount of the Company's 4.22% Senior Notes due August 15, 2028, and the RGRT issued $65.0 million in aggregate 
principal amount of its 4.07% Senior Guaranteed Notes due August 15, 2025. Also, on September 13, 2018, the Company and the 
Bank of New York Mellon Trust Company, N.A., as trustee of the RGRT, entered into a $350.0 million third amended and restated 
credit agreement. Additionally, the Company is preparing for potential transactions related to the 2009 Series A and Series B PCBs. 
On February 1, 2019, the Company purchased in lieu of redemption all the $63.5 million 2009 Series A 7.25% PCBs. The bonds 
were purchased utilizing funds borrowed under the RCF. The Company is currently holding the bonds and may remarket them or 
replace them with debt instruments of equivalent value at a future date depending on the Company's financing needs and market 
conditions and in accordance with FERC action expected in March 2019 in response to the Company’s most recent FERC application 
(see below). See Part II, Item 8, Financial Statements and Supplementary Data, Note J of Notes to Financial Statements for further 
discussion on long-term debt and financing obligations. 

On January 30, 2019, the Company submitted an application with the FERC seeking approval to issue shares of common 
stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more transactions. Included in the 
FERC application, the Company also requested various debt-related authorizations: approval to utilize the existing RCF for short-
term borrowing not to exceed $400.0 million at any one time; to issue up to $225.0 million in new long-term debt; and to remarket 
the $63.5 million 2009 Series A 7.25% PCBs and the $37.1 million 2009 Series B 7.25% PCBs in the form of replacement bonds 
or senior notes of equivalent value, not to exceed $100.6 million. If approved, the FERC authorization would supersede its prior 
approvals. 

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

by the Federal Power Act and the FERC.

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

The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's 
uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Part II, Item 8, Financial Statements 
and Supplementary Data, Note F of Notes to Financial Statements for further discussion of spent fuel storage and disposal costs.

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

The Company provides firm capacity and associated energy to the 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 OATT. The contract includes a formula-based rate that is updated annually to recover non-fuel generation costs and a 
fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC. The Company's 
service to RGEC is regulated by FERC. 

69

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

E.

Regulatory Assets and Liabilities

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

Amortization
Period Ends

December 31,
2018

December 31,
2017

Regulatory assets

Regulatory tax assets.................................................................
Loss on reacquired debt (b).......................................................
Final coal reclamation ...............................................................
Four Corners decommissioning ................................................
Nuclear fuel postload daily financing charge............................
Unrecovered issuance costs due to reissuance of PCBs (b)......
Texas 2015 rate case costs (f)....................................................
Texas 2017 rate case costs.........................................................
Texas relate back surcharge (g).................................................
New Mexico renewable energy credits and related costs (h)....
New Mexico Palo Verde deferred depreciation ........................
Other regulatory assets..............................................................

Total regulatory assets

Current portion (amount due within one year)
Regulatory assets, non-current

(a)
May 2035
(c)
(d)
(e)
August 2042
January 2021
January 2021
January 2019
June 2022
(i)
various

Regulatory liabilities

Regulatory tax liabilities ...........................................................
Accumulated deferred investment tax credit.............................
Texas energy efficiency.............................................................
New Mexico energy efficiency .................................................
Fuel revenue over-recovery.......................................................
Other regulatory liabilities ........................................................

(j)
(k)
(l)
(l)
(m)
various

Total regulatory liabilities

Current portion (amount due within one year)
Regulatory liabilities, non-current

$

$

$

$

39,519
14,074
4,065
5,813
3,717
728
747
2,634
—
4,709
4,111
1,703
81,820
6,972
74,848

291,557
7,872
—
1,694
11,047
1,086
313,256
14,686
298,570

$

$

$

$

40,512
14,926
4,726
6,604
3,536
761
1,144
3,642
8,591
5,823
4,263
1,508
96,036
—
96,036

289,013
4,816
895
1,394
6,225
567
302,910
6,225
296,685

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

(b) This item is recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance.
(c) This item relates to coal reclamation costs associated with Four Corners. The Texas portion was approved for recovery in
PUCT Docket No. 46308 and will be recovered over seven years through June 2023. The New Mexico amortization period
will be established in the next general rate case.

(d) This item relates to the decommissioning of Four Corners. The Texas portion was approved for recovery in PUCT Docket
No. 46308 and will be recovered over seven years through July 2024. The New Mexico amortization period will be established
in the next general rate case.

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

(e) This item is recovered through fuel recovery mechanisms established by tariffs.
(f)
(g) This item relates to the recovery of revenues through two separate surcharges; one for the 2015 Texas Retail Rate Case relate
back revenues beginning October 1, 2016, and ending September 30, 2017, and a second surcharge for the 2017 Texas Retail

70

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Rate Case relate back revenues beginning January 10, 2018, and ending January 9, 2019. Amounts over-recovered through 
these  surcharges  will  be  addressed  in  the  next  Texas  fuel  reconciliation.  See  Part  II,  Item  8,  Financial  Statements  and 
Supplementary Data, Note D of Notes to Financial Statements for further discussion.

(h) This item relates to renewable energy credits and procurement plan costs, of which a component has been approved for

(i)

(j)

recovery in the NMPRC Final Order. The remaining balance will be requested for recovery in the next general rate case.
The amortization period for this item is based upon the U.S. Nuclear Regulatory Commission ("NRC") license life for each
unit at Palo Verde.
This item primarily relates to the reduction in the federal corporate income tax rate from 35% to 21% as enacted by the TCJA.
The amortization period for the recovery on this item will be addressed in the next base rate filings in all jurisdictions. See
Part II, Item 8, Financial Statements and Supplementary Data, Note K of Notes to Financial Statements for further discussion.

(k) The amortization period is based upon the life of the associated assets.
(l)
(m) This item represents the net over-recovery of fuel and purchased power expense which is refunded to customers through fuel

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

rates.

71

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

F.

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, 2018 (in thousands):

Gross
Plant

Nuclear production ....................................................................... $ 1,024,771
1,007,526
Steam and other ............................................................................
2,032,297
Total production ....................................................................
557,255
Transmission ................................................................................
1,257,509
Distribution...................................................................................
232,278
General .........................................................................................
102,070
Intangible......................................................................................
Total....................................................................................... $ 4,181,409

$

Accumulated
Depreciation

Net
Plant
666,165
770,508
1,436,673
286,367
868,007
158,281
40,815
$ (1,391,266) $ 2,790,143

(358,606) $
(237,018)
(595,624)
(270,888)
(389,502)
(73,997)
(61,255)

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

A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2018

and 2017 is as follows (in thousands):

Electric plant in service ............................................................... $ 1,024,771
(358,606)
Accumulated depreciation ...........................................................
44,719
Construction work in progress.....................................................
710,884

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

$

$

94,155
(75,096)
1,511
20,570

$

$

994,075
(338,699)
40,946
696,322

$

$

97,603
(72,822)
1,014
25,795

December 31, 2018

December 31, 2017

Palo Verde

Other (a)

Palo Verde

Other (a)

(a) Includes three jointly-owned transmission lines.

_______________

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

2016 ..................................................................................... $
2017 .....................................................................................
2018 .....................................................................................
2019 (estimated) ..................................................................
2020 (estimated) ..................................................................
2021 (estimated) ..................................................................
2022 (estimated) ..................................................................
2023 (estimated) ..................................................................

5,302
6,409
7,297
7,263
6,867
5,934
5,047
4,070

72

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 dated August 23, 1973, as amended ("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, O&M expense, and capital costs. The Company’s share of direct expenses in Palo Verde and other jointly-
owned utility plants is reflected in fuel expense, O&M expense, miscellaneous other deductions, and taxes other than income taxes 
in the Company’s statements of operations. The ANPP Participation Agreement provides that if a participant fails to meet its 
payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting 
participant. Because it is impracticable to predict defaulting participants, the Company cannot estimate the maximum potential 
amount of future payment, if any, which could be required under this provision.

Nuclear Regulatory Commission. The NRC regulates the operation of all commercial nuclear power reactors in the U.S., 
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 the NDT 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, 2018, the NDT had a balance of $276.9 million, which is above its minimum funding level. The Company monitors 
the status of the NDT and adjusts contributions accordingly.

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

Spent Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987, the 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 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. Pursuant to the terms of the August 18, 2014 settlement agreement, and as 
amended with the DOE, APS files annual claims for the period July 1 of the then-previous year to June 30 of the then-current year 
on behalf of itself and those utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to 
Palo Verde based upon the ANPP Participation Agreement dated August 23, 1973. The settlement agreement, as amended, provides 
APS with a method for submitting claims and receiving recovery for costs incurred through December 31, 2016, which has been 

73

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

extended to December 31, 2019. The Company's share of costs recovered in 2018, 2017, and 2016, respectively are presented 
below (in thousands):

Costs Recovery Period

Amount Refunded

Amount Credited to
Customers through Fuel
Adjustment Clauses

Period Credited to
Customers

July 2016 - June 2017

$

July 2015 - June 2016

July 2014 - June 2015

$

1,413

1,779

1,884

1,121

1,432

1,581

March 2018

March 2017

March 2016

On October 31, 2018, APS filed a $10.2 million claim for the period July 1, 2017 through June 30, 2018. The Company's 
share of this claim is approximately $1.6 million. This claim is pending DOE review. The majority of the reimbursement received 
by the Company is expected to be credited to customers through the applicable fuel adjustment clauses.

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

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

Liability and Insurance Matters. The Palo Verde Participants have insurance for public liability resulting from nuclear energy 
hazards to the full limit of liability under federal law, which is currently at $14.1 billion. This potential liability is covered by 
primary liability insurance provided by commercial insurance carriers in the amount of $450.0 million, and the balance is covered 
by an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the 
accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per 
incident basis. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately 
$137.6 million, subject to an annual limit of $20.5 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 $62.1 million, with an annual 
payment limitation of approximately $9.7 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 $2.3 billion. The Company has also secured insurance against 
portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen 
outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy 
conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies. 
If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance 
programs, the Company could be assessed retrospective premium adjustments of up to $13.5 million for the current policy period. 

Palo Verde O&M Expense. Included in other O&M expenses are expenses associated with Palo Verde as follows (in 

thousands):

Years Ended December 31,

2018

2017

2016

$

96,454

$

99,364

$

96,914

74

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Four Corners

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

G.

Accounting for Asset Retirement Obligation

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

The ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2016 Study. See 
Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements. The ARO liability is 
calculated by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium 
factor. The resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted 
discount rate. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future 
current cost estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume 
responsibility for the permanent disposal of spent fuel, such costs have not been included in the ARO calculation. The Company 
maintains six external trust funds with an independent trustee that are legally restricted to settling its ARO at Palo Verde. The fair 
value of the funds at December 31, 2018 is $276.9 million.

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

Escalation
Rate

Credit-Risk
Adjusted
Discount Rate

Original ARO liability.........................
Incremental ARO liability (2010) .......
Incremental ARO liability (2016) .......

3.60%
3.60%
3.25%

9.50%
6.20%
4.34%

75

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

An analysis of the activity of the Company’s total ARO liability from January 1, 2016 through December 31, 2018, including 
the effects of each year’s estimate revisions, is presented below (in thousands). In 2017, the estimate revision reflects increases 
in the estimated cash flows related to Palo Verde's decommissioning due to implementing the 2016 Study. In 2016, the settled 
liabilities reflect the sale of the Company's interest in Four Corners including the related ARO. 

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

2018
93,029
—
(272)
—
8,351
101,108

$

$

2017
81,800
138
(19)
3,461
7,649
93,029

$

$

2016
81,621
—
(6,993)
—
7,172
81,800

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

H.

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 
("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 of Notes to Financial Statements, 
the Company accounts for its stock-based long-term incentive plan under the FASB guidance for stock-based compensation.

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

76

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The expense, deferred tax benefit, and current tax benefit recognized related to restricted stock and other stock-based awards 

in 2018, 2017 and 2016 is presented below (in thousands):

2018

2017

2016

Expense (a).......................................
Deferred tax benefit .........................
Current tax benefit recognized.........

$

3,198

$

671

117

$

2,997

1,049

318

2,594

908

183

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

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

2018, 2017 and 2016 is presented below (in thousands):

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

$

$

3,771

3,212

$

3,711

2,803

2,515

1,993

2018

2017

2016

The unvested restricted stock transactions for 2018 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, 2017 (b)...

106,235

$

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

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

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

Restricted shares outstanding at December 31, 2018 (b)...

62,348

(69,948)
(4,727)
93,908

45.76

54.49

45.93

42.29

51.60

$

2,009

$

4,708

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

of the outstanding restricted stock of approximately one year.

(b) Excludes the stock-based retention grant to the President and Chief Executive Officer ("CEO") of 27,624 shares. See "Restricted

Stock with a Market Condition (Performance Shares)" section below for further details.

The weighted average fair value per share at grant date for restricted stock and other stock-based awards granted during 

2018, 2017 and 2016 were: 

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

54.49

$

49.78

$

40.95

2018

2017

2016

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.

77

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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

Detail of performance shares vested follows:

Date Vested

Payout
Ratio

Performance
Shares Awarded

Compensation
Costs Expensed

(In thousands)

Period
Compensation
Costs Expensed

Aggregated
Intrinsic Value

(In thousands)

January 30, 2019

71%

39,923

$

2,143

2016-2018

January 31, 2018

175%

68,379

1,499

2015-2017

January 25, 2017

January 27, 2016

32%

0%

11,314

0

932

851

2014-2016

2013-2015

2,046

3,569

512

—

In 2019, 2020 and 2021, subject to meeting certain performance criteria and continuous service requirements, additional 
performance  shares  could  vest.  In  accordance  with  the  FASB  guidance  related  to  stock-based  compensation,  the  Company 
recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service 
period and the compensation expense is only adjusted for forfeitures. As of December 31, 2018, the maximum number of shares 
that can be issued under the plan are 223,885 shares. 

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

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

Number
Outstanding

Weighted
Average
Grant Date
Fair Value

Unrecognized
Compensation
Expense (b)

Aggregate
Intrinsic Value

(In thousands)

(In thousands)

Performance shares outstanding at December 31, 2017 (a)..

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

Performance shares vested ....................................................

Performance shares forfeited.................................................

172,591

$

45,977
(39,077)
(3,646)

38.21

48.99

38.36

42.47

Performance shares outstanding at December 31, 2018 (a)..

175,845

40.90

$

1,961

$

8,815

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

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

78

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

A summary of information related to performance shares for 2018, 2017 and 2016 is presented below: 

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) (c) .............................................
Deferred tax benefit related to compensation expense (in thousands) (b) ..

2018

2017

2016

48.99

$

42.62

$

38.11

1,499

2,040

2,271

477

298

512

2,012

704

—

—

1,655

579

_____________________
(a) Based on a 100%, 32% and 0% performance level, respectively.
(b) Includes adjustments for estimated forfeitures.
(c) Includes President and CEO retention grant.

Repurchase Program

No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2018. Detail 

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

Shares repurchased (b) (c)...........................................................................
Cost, including commission (in thousands) ................................................ $
Total remaining shares available for repurchase at December 31, 2018.....

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 that were not

part of the Company's repurchase program.

(c) 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 has issued 345,352 treasury shares since 2015
including 96,783 shares during 2018.

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 the repurchased shares may be retired.

Dividend Policy

On December 28, 2018, the Company paid $14.6 million in quarterly cash dividends to shareholders. The Company paid a 
total of $57.5 million, $53.3 million and $49.6 million in cash dividends during the twelve months ended December 31, 2018, 
2017 and 2016, respectively. On January 31, 2019, the Board of Directors declared a quarterly cash dividend of $0.36 per share 
payable on March 29, 2019 to shareholders of record as of the close of business on March 15, 2019. 

79

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,
2017

2018

2016

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 ............................................

40,521,364
121,276
40,642,640

40,414,556
120,635
40,535,191

40,350,688
57,345
40,408,033

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:

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

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

84,315
(297)
84,018

84,315
(296)
84,019

1.415
0.655
2.070

1.415
0.655
2.070

$

$

$

$

$

$

$

$

98,261
(368)
97,893

98,261
(368)
97,893

1.315
1.105
2.420

1.315
1.105
2.420

$

$

$

$

$

$

$

$

96,768
(321)
96,447

96,768
(321)
96,447

1.225
1.165
2.390

1.225
1.165
2.390

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,
2017
67,739

2018
62,836

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

22,815

—

2016
53,703

47,246

_____________________
(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.

Authorization to Issue and Retire Shares

On January 30, 2019, the Company submitted an application with both the NMPRC and the FERC seeking approval to issue 
shares of common stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more transactions.
In order to align the number of shares of common stock held as treasury stock by the Company with various regulatory applications, 
filings and orders, on January 31, 2019, the Board of Directors of the Company approved the cancellation of 1.4 million shares 
of Common Stock held as treasury shares by the Company effective upon the later of approval by the FERC of the accounting 
treatment of the cancellation and March 31, 2019. 

80

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

I.

Accumulated Other Comprehensive Income (Loss)

Upon adoption of ASU 2016-01, Financial Instruments-Overall, the Company recorded, on January 1, 2018, a cumulative 
effect  adjustment,  net  of  income  taxes,  to  increase  retained  earnings  by  $41.0  million  with  an  offset  to AOCI.  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, 2015............................ $

(29,869) $

27,765

$

(11,810)

$

(13,914)

Other comprehensive income before

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

7,363

6,904

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

Balance at December 31, 2016............................

Other comprehensive income before

(1,422)

(23,928)

(6,206)

28,463

—

159

(11,651)

14,267

(7,469)

(7,116)

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

7,951

20,251

—

28,202

Amounts reclassified from accumulated other
comprehensive income (loss)...................
Balance at December 31, 2017............................

(1,813)
(17,790)

(8,524)
40,190

309
(11,342)

Cumulative effect adjustment .........................

—

(41,028)

Other comprehensive loss before

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

(4,589)

(3,240)

—

—

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

Balance at December 31, 2018............................ $

(2,544)
(24,923) $

1,136
(2,942) $

423
(10,919)

$

(10,028)
11,058

(41,028)

(7,829)

(985)
(38,784)

81

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Amounts reclassified from Accumulated Other Comprehensive Income (Loss) for the twelve months ended December 31, 

2018, 2017 and 2016 are as follows (in thousands):

Details about Accumulated Other
Comprehensive Income (Loss) Components

2018

2017

2016

Affected Line Item in
the Statements of
Operations

Amortization of pension and post-

retirement benefit costs:

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

$

9,657

$

9,657

$

7,407

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

(6,387)

(6,776)

(4,965)

3,270

2,881

2,442

Miscellaneous
non-operating
income

Miscellaneous
non-operating
deductions

Income (loss)
before income
taxes

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

(726)

2,544

(1,068)
1,813

Income tax
(benefit) expense

(1,020)
1,422 Net income (loss)

Marketable securities:

Net realized gain (loss) on sale of
securities.........................................

(1,445)

10,626

7,640

(1,445)

10,626

7,640

Investment and
interest income,
net

Income (loss)
before income
taxes

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

309

(1,136)

(2,102)
8,524

Income tax
(benefit) expense

(1,434)
6,206 Net income (loss)

Loss on cash flow hedge:

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

(568)

(532)

(498)

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

(568)

145

(423)

(532)

223
(309)

(498)

Income tax
(benefit) expense
339
(159) Net income (loss)

Interest on long-
term debt and
revolving credit
facility

Income (loss)
before income
taxes

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

$

985

$

10,028

$

7,469

82

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

J.

Long-Term Debt and Financing Obligations

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

December 31,

2018

2017

(In thousands)

Long-Term Debt:

Pollution Control Bonds (1):

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

$

62,695
36,544
58,530
157,769

62,657
36,518
58,501
157,676

Senior Notes (2):

Senior Notes-Public:

3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)...............
6.00% Senior Notes, net of discount, due 2035 (6.58% effective interest rate)...............
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)...............
5.00% Senior Notes, net of discount, due 2044 (4.93% effective interest rate)...............

149,269
394,231
147,441
302,845
993,786

Senior Notes-Private Placement:

4.22% Senior Notes, net of discount, due 2028 (4.30% effective interest rate)...............
Total Senior Notes ...................................................................................................

124,157
1,117,943

RGRT Senior Notes (3):

149,101
394,040
147,384
302,901
993,426

—
993,426

5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate).........................
4.07% Senior Guaranteed Notes, due 2025 (4.18% effective interest rate).....................
Total RGRT Senior Notes .......................................................................................
Total long-term debt .......................................................................................

44,928
64,579
109,507
1,385,219

44,886
—
44,886
1,195,988

Financing Obligations:

Revolving Credit Facility (4)...................................................................................................
Total long-term debt and financing obligations......................................................

49,207
1,434,426

173,533
1,369,521

Current Portion (amount due within one year):

Current maturities of long term debt (1) ..........................................................................
Short-term borrowings under the revolving credit facility...............................................

(99,239)
(49,207)
$ 1,285,980

—
(173,533)
$ 1,195,988

_____________________
(1) Pollution Control Bonds

The Company has three series of tax exempt unsecured PCBs in aggregate principal amount of $159.8 million. The 7.25%
2009 Series A and the 7.25% 2009 Series B PCBs with an aggregate principal amount, together, of $100.6 million have
optional redemptions beginning in February 2019 and April 2019, respectively, at which time the Company expects to repay,
remarket or replace these bonds. The principal and related unamortized issuance cost on these PCBs were reclassified to
current  maturities  of  long-term  debt  as  of  December  31,  2018.  On  February 1,  2019,  the  Company  purchased  in  lieu  of
redemption all of the 7.25% 2009 Series A with a principal amount of $63.5 million utilizing funds borrowed under the RCF.
The Company is currently holding the bonds and may remarket them or replace them with debt instruments of equivalent
value at a future date depending on financing needs and market conditions.

(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

83

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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 P of Notes to Financial Statements. This amortization is 
included in the effective interest rate of the 6.00% Senior Notes. 

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

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

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

On June 28, 2018, the Company entered into a note purchase agreement with several institutional purchasers under which the 
Company issued and sold $125 million aggregate principal amount of 4.22% Senior Notes due August 15, 2028. The net 
proceeds from the issuance of these senior notes were used to repay outstanding short-term borrowings under the RCF for 
working capital and general corporate purposes. The Company will pay interest on the notes semi-annually on February 15 
and August 15 of each year until maturity, beginning on February 15, 2019. The Company 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 note purchase agreement requires compliance with certain covenants, including a total debt to capitalization ratio. 
The Company was in compliance with these requirements throughout 2018. The issuance and sale of these senior notes was 
made in reliance on a private placement exemption from the registration provisions of the Securities Act of 1933, as amended 
("Securities Act").

(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 issued
and sold to the purchasers $110 million aggregate principal amount of Senior Notes ("RGRT Notes"). In August 2015 and
2017, $15.0 million and $50.0 million of the RGRT Notes, respectively, matured and were paid with borrowings from the
RCF.  The  Company  guarantees  the  payment  of  principal  and  interest  on  the  RGRT  Notes.  In  the  Company’s  financial
statements, the assets and  liabilities of RGRT  are reported as assets  and liabilities of  the Company. In August  2020,  the
remaining $45.0 million of these RGRT Notes mature.

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

On June 28, 2018, the RGRT and the Company entered into a note purchase agreement with several institutional purchasers
under  which  the  RGRT  issued  and  sold  $65  million  aggregate  principal  amount  of  4.07%  Senior  Guaranteed  Notes  due
August 15, 2025 ("RGRT Senior Notes"). The net proceeds from the RGRT Senior Notes were used to repay outstanding
short-term borrowings under the RCF to finance nuclear fuel purchases. The Company guaranteed the payment of principal
and interest on the RGRT Senior Notes. RGRT’s assets, liabilities and operations are consolidated in the Company’s financial
statements and the RGRT Senior Notes are included as long-term debt on the balance sheet. The issuance and sale of the
RGRT Senior Notes was made in reliance on a private placement exemption from the registration provisions of the Securities
Act.

84

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

RGRT pays interest on the senior notes above on February 15 and August 15 of each year until maturity, beginning on February 
15, 2019. RGRT may redeem the senior 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 note purchase agreement requires compliance with 
certain covenants, including a total debt to capitalization ratio. The Company and RGRT were in compliance with these 
requirements throughout 2018.

(4) Revolving Credit Facility

On January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the
RCF with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication
agent, and various lending banks party thereto. As of December 31, 2016, the Company had available $300 million and the
ability to increase the RCF by up to $100 million with a term ending January 2019. On January 9, 2017, the Company exercised
its option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50
million to $350 million.

On September 13, 2018, the Company and The Bank of New York Mellon Trust Company, N.A., as trustee of the RGRT,
entered  into  a  third  amended  and  restated  credit  agreement  ("RCF  Agreement")  with  MUFG  Union  Bank,  N.A.,  as
administrative agent and as syndication agent, various issuing banks and lending banks party thereto. Under the terms of the
RCF Agreement, the Company has available a $350 million RCF with a $50 million subfacility for the issuance of letters of
credit, and the Company extended the term of the Company's existing $350 million revolving credit agreement from January 14,
2020 to September 13, 2023 ("Maturity Date"). The Company may increase the RCF by up to $50 million (to a total of $400
million) during the term of the RCF Agreement, upon the satisfaction of certain conditions more fully set forth in the RCF
Agreement, including obtaining commitments from lenders or third party financial institutions. In addition, 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 more fully set forth in the RCF Agreement, including requisite lender approval.

The RCF Agreement provides that amounts borrowed by the Company may be used for, among other things, working capital
and  general  corporate  purposes. Any  amounts  borrowed  by  the  RGRT  may  be  used,  among  other  things,  to  finance  the
acquisition and cost to process nuclear fuel. Amounts borrowed by the RGRT are guaranteed by the Company and the balance
borrowed  under  the  RCF Agreement  is  recorded  as  short-term  borrowings  on  the  balance  sheet. The  RCF Agreement  is
unsecured. The RCF Agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The
Company  is  in  compliance  with  these  requirements  throughout  2018.  In August  2017,  $50.0  million  aggregate  principal
amount of Series B 4.47% Senior Notes of the RGRT matured and was paid with borrowings from the RCF. On February 1,
2019, the Company purchased in lieu of redemption all of the 7.25% 2009 Series A PCBs with a principal amount of $63.5
million utilizing funds borrowed under the RCF. The Company is currently holding the bonds and may remarket them or
replace them with debt instruments of equivalent value at a future date depending on the Company's financing needs and
market conditions. As of December 31, 2018, the total amount borrowed by the RGRT was $26.2 million for nuclear fuel
under the RCF. As of December 31, 2018, $23.0 million of borrowings were outstanding under this facility for working capital
and general corporate purposes. The weighted average interest rate on the RCF was 3.8% as of December 31, 2018.

As of December 31, 2018, the principal amount of scheduled maturities for the next five years of long-term debt are as follows

(in thousands): 

2019 (1) ................................................. $
2020.......................................................
2021.......................................................
2022.......................................................
2023.......................................................

100,600
45,000
—
150,000
—

_____________________
(1) The 7.25% 2009 Series A and the 7.25% 2009 Series B PCBs with an aggregate principal amount, together, of $100.6

million have optional redemptions beginning in February 2019 and April 2019, respectively, at which time the Company
expects to repay, remarket or replace these bonds.

85

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

K.

Income Taxes

On December 22, 2017, the TCJA was enacted. The TCJA includes significant changes to the IRC, including amendments 
that significantly changed the taxation of business entities and includes specific provisions related to regulated public utilities. 
The more significant changes that impact the Company included in the TCJA are reductions in the corporate federal income tax 
rate from 35% to 21%, elimination of the corporate alternative minimum tax provision, additional limitations on deductions of 
executive compensation, and limitations on the utilization of NOLs arising after December 31, 2017, to 80% of taxable income 
with no carryback but with an indefinite carryforward. The specific provisions related to regulated public utilities in the TCJA 
generally provide for the continued deductibility of interest expense, the elimination of bonus depreciation for property acquired 
and placed into service after December 31, 2017, and the continuance of rate normalization requirements for accelerated depreciation 
benefits and changes to deferred tax balances as a result of the change in the corporate federal income tax rate. Although the 
Company  recorded  provisional  estimates  of  the  impact  of  the TCJA,  as  of  the  date  of  enactment,  no  significant  subsequent 
adjustments to the provisional estimates were recorded during the one-year measurement period as permitted by the SEC in SAB 
118. The results for the twelve months ended December 31, 2018 and 2017 contain the impact of the TCJA.

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

In February 2018, the FASB issued ASU 2018-02, which addresses concerns that the tax reduction due to the change in the 
corporate tax rate from 35% to 21% would be "stranded" in AOCI. ASU 2018-02 allows companies to reclassify stranded taxes 
from AOCI to retained earnings. The Company is currently evaluating the impact of ASU 2018-02 and its impact on regulated 
utilities. See Part II, Item 8, Financial Statements and Supplementary Data, Note B of Notes to Financial Statements for further 
discussion on new accounting standards.

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

December 31, 2018 and 2017 are presented below (in thousands):

December 31,

2018

2017

Deferred tax assets:

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

$

12,521
8,855
31,874
21,305
63,378
2,483
2,673
143,089

24,035
16,620
32,606
19,530
63,794
1,405
—
157,990

Deferred tax liabilities:

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

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

(437,465)
(30,757)
—
(468,222)
(325,133) $

(426,077)
(34,520)
(2,416)
(463,013)
(305,023)

Based on the average annual earnings before taxes for the prior three years, and excluding the effects of unusual or infrequent 

items, the Company believes that the deferred tax assets will be fully realized.

86

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The Company recognized income tax expense for 2018, 2017 and 2016 as follows (in thousands): 

Years Ended December 31,

2018

2017

2016

Income tax expense (benefit):

Federal:

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

(4,638) $
24,121
19,483

State:

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

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

1,888
1,941
3,829
3,056
26,368

$

2,507
46,089
48,596

(897)
1,816
919
1,489
51,004

$

$

2,642
47,909
50,551

766
3,285
4,051
(684)
53,918

As of December 31, 2018, the Company had $8.9 million of alternative minimum tax ("AMT") credit carryforwards. Based 
on the TCJA provisions, the Company may claim a refund of 50% of the remaining AMT credits in 2019 and 2020. Any AMT 
credits remaining after 2020 will be refunded in 2021. As of December 31, 2018, the Company had $11.9 million of federal and 
$0.8 million of state tax loss carryforwards. Under the TCJA, NOLs arising in tax years ending after 2017 cannot be carried back 
but can be carried forward indefinitely. The use of NOLs generated after 2017 to offset taxable income is limited to 80% of taxable 
income. Federal NOLs generated prior to 2018 are able to offset 100% of future taxable income to the extent available but have 
lives of only 20 years.

Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 21% in 2018 and 

35% in 2017 and 2016 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,

2018
23,243

2017
52,243

$

2016
52,740

$

3,059

(182)
(682)
930
26,368

$

597

450
(2,562)
276
51,004

$

2,633

(475)
(2,369)
1,389
53,918

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

23.8%

34.2%

35.8%

The Company files income tax returns in the U.S. federal jurisdiction and in the states of Texas, New Mexico and Arizona. 
The Company is no longer subject to tax examination by the taxing authorities in the federal, Arizona and New Mexico jurisdictions 
for years prior to 2014. In August 2017, the Company reached an agreement with the Texas Comptroller of Public Accounts and 
settled audits in Texas for tax years 2007 through 2011. 

In the third quarter of 2016, the Company changed its accounting for state income taxes from the flow-through method to 
the normalization method in accordance with the 2016 PUCT Final Order and the NMPRC Final Order. Under the flow-through 
method, the Company previously recorded deferred state income taxes and regulatory liabilities and assets offsetting such deferred 
state income taxes at the expected cash flow to be reflected in future rates. Upon implementation of normalization, the Company 
began amortizing the net regulatory asset for deferred state income taxes to deferred income tax expense over a 15-year period as 
allowed by the regulators. In the third quarter of 2016, the Company began recording deferred state income tax expense as required 
by normalization, retroactive to January 2016 as provided in the final orders. The impact of the change was additional income tax 
expense of $2.3 million, $1.9 million and $5.1 million for the years ended December 31, 2018, 2017 and 2016, respectively.

87

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition 
and measurement of a tax position taken or expected to be taken in a tax return. The Company recorded a decrease of $1.2 million
(net of an increase of $0.5 million), and a decrease of $0.4 million (net of an increase of $0.3 million), in 2017 and 2016, respectively, 
related to transmission and distribution costs and other amounts deducted in current and prior year Texas franchise tax returns. 
The Company recorded an unrecognized tax position of $0.5 million in 2018, $0.1 million in 2017 and a decrease of $0.3 million
in 2016 related to tax credits taken and apportionment factors used in prior year Arizona income tax returns, which have been 
settled through audit. A reconciliation of the December 31, 2018, 2017 and 2016 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 ....................................................................................... $

2018

2017

2016

4,200
—
(200)
700
—
4,700

$

$

5,300
200
—
400
(1,700)
4,200

$

$

6,000
400
—
100
(1,200)
5,300

If recognized, $1.6 million of the unrecognized tax position at December 31, 2018, would reduce the effective tax rate. The 
Company  recognized  income  tax  expense  for  the  increase  in  unrecognized  tax  positions  of  $0.5  million  for  the  year  ended 
December 31, 2018. 

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. For the 
years  ended  December 31,  2018  and  2016,  the  Company  recognized  tax  expense  interest  of  $0.6  million  and  $0.1  million, 
respectively. For the year ended December 31, 2017 the Company recognized a tax benefit of $0.2 million. The Company had 
approximately $1.2 million and $0.7 million accrued for the payment of interest and penalties at December 31, 2018 and 2017, 
respectively. 

88

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

L.

Commitments, Contingencies and Uncertainties

Power Purchase and Sale Contracts

To supplement its own generation and operating reserve requirements and to meet its RPS requirements, 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  RPS  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 .

Power Purchase and Sale Agreement .

Freeport

Freeport

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

Hatch Solar Energy Center
I, LLC

25 MW

December 2008 through December 
2021

100 MW

June 2006 through December 2021

5 MW

July 2011 through July 2036

July 2011

Commercial

Operation

Date

N/A

N/A

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

Solar Roadrunner, LLC

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 May 2034

May 2014

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

Newman Solar LLC

10 MW

December 2014 through December 
2044

December 2014

The  Company  has  a  firm  100  MW  Power  Purchase  and  Sale Agreement  ("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 
2021.

The Company has entered into several power purchase agreements to help meet its RPS 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 Solar Roadrunner, LLC, a subsidiary of Global Infrastructure 
Partners, (formerly known as NRG Solar Roadrunner LLC) to purchase all of the output of a solar photovoltaic plant built in 
southern New Mexico, which began commercial operation in August 2011. In addition, the Company has 25-year purchase power 
agreements to purchase all of the output of two additional solar photovoltaic plants located in southern New Mexico, SunE EPE1, 
LLC and SunE EPE2, LLC, which began commercial operation in June 2012 and May 2012, respectively. In September 2017, 
Longroad Solar Portfolio Holdings, LLC purchased SunE EPE1, LLC, and in October 2017, Silicon Ranch Corporation purchased 
SunE EPE2, LLC with the Company's consent per the terms of both power purchase agreements. 

Furthermore, the Company has a 20-year power purchase 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 power purchase 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 Newman. This solar photovoltaic plant began commercial operation in December 2014. 

89

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. 

National  Ambient  Air  Quality  Standards  ("NAAQS").  Under  the  U.S.  Clean Air Act  ("CAA"),  the  U.S  Environmental 
Protection Agency  ("EPA")  sets  NAAQS  for  six  criteria  pollutants  considered  harmful  to  public  health  and  the  environment, 
including particulate matter, nitrogen oxide, carbon monoxide, ozone and sulfur dioxide. On October 1, 2015, the EPA released a 
final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion 
("ppb")  to  70 ppb.  The  EPA  published  the  Final  Rule  on  June 4,  2018,  designating  El Paso  County,  Texas,  as  "attainment/
unclassifiable"  under  the  2015  ozone  NAAQS  and  designating  a  section  of  southern  Doña  Ana  County,  New Mexico,  as 
"nonattainment." In August 2018, several petitions for review of the Final Rule were filed in the U.S. Court of Appeals for the 
D.C. Circuit. One of these petitions, filed by the City of Sunland Park, New Mexico, specifically challenges the "attainment/
unclassifiable" designation  of  El Paso  County, Texas. The  Company and  other  intervenors  filed and  were  granted  motions to
intervene in the challenges to EPA's 2015 ozone NAAQS designations. A briefing schedule extending through July 2019 has been
established for the case.

States, including New Mexico, that contain any areas designated as nonattainment are 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. 

Climate Change. The federal government has considered, proposed and/or finalized legislation or regulations limiting GHG 
emissions,  including  carbon  dioxide.  In  particular,  the  U.S.  Congress  has  considered  legislation  to  restrict  or  regulate  GHG 
emissions. In October 2015, the EPA published a rule establishing guidelines for states to regulate carbon dioxide emissions from 
existing power plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. On August 31, 2018, 
the EPA published a proposal to replace the CPP called the Affordable Clean Energy ("ACE") rule. The ACE rule has not yet been 
finalized. At this time the Company cannot determine the impact that the CPP, the ACE rule, and related proposals and legal 
challenges may have on our financial position, results of operations or cash flows. 

Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice, on behalf of the EPA, and 
APS have been engaged in substantive settlement negotiations in an effort to resolve certain pending matters. The allegations being 
addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary 
under the CAA to reduce sulfur dioxide, nitrogen oxides, and particulate matter, and that APS failed to obtain an operating permit 
under Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. 
District Court for the District of New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On 
August 17, 2015, the U.S. District Court 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, 2018, the Company has accrued its remaining unpaid share of 
approximately $0.2 million related to this matter. 

Lease Agreements

The Company leases land in El Paso, Texas, adjacent to Newman under a lease that expires in June 2033 with a renewal 
option of 25 years. The Company also has several other leases for office, parking facilities and equipment that expire within the 
next 5 years. The Company has transmission and distribution lines that are operated under various land rights agreements, including 
easements, leases, permits and franchises. The majority of these agreements include renewal options that the Company routinely 
exercises. These agreements generally do not impose any restrictions relating to issuance of additional debt, payment of dividends 
or entering into other lease arrangements. 

90

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The Company's total annual rental expense related to operating leases was $1.7 million, $2.4 million, and $1.7 million for 
2018, 2017 and 2016, respectively. As of December 31, 2018, the Company’s minimum future rental payments for the next five 
years are as follows (in thousands):

2019................................................. $
2020.................................................
2021.................................................
2022.................................................
2023.................................................

923
820
700
544
526

Union Matters

The Company has approximately 1,100  employees, about 37% of whom are covered by a collective bargaining agreement. 
The  International  Brotherhood  of  Electrical Workers  Local  960  ("Local  960")  represents  the  Company’s  employees  working 
primarily in power generation, transmission and distribution, communications, material services, fleet services, facilities services, 
customer services and meter reading, and field services. The Company entered into a collective bargaining agreement effective 
September 3, 2016, with Local 960 for a three-year term ending September 3, 2019. The agreement provides for pay increases of 
3% on September 3, 2016, September 3, 2017 and September 3, 2018, respectively. The Company presently anticipates negotiating 
a new three-year collective bargaining agreement to supersede the current collective bargaining agreement after the initial three-
year term of the current collective bargaining agreement ends on September 3, 2019. The Company cannot predict the outcome 
of such negotiations and its impact on the Company's operating results and cash flows.

M.

Litigation

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

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

91

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

N.

Employee Benefits

The Company adopted ASU 2017-07, Compensation-Retirement Benefits, effective January 1, 2018. Upon adoption 
of the new standard, the service cost is included in "Operations and maintenance" in the Company's Statements of Operations. 
The expected return on plan assets is included in "Investment and interest income, net". The amortization of prior service 
benefit and amortization of gains are included in "Miscellaneous non-operating income". The amortization of prior service 
cost and amortization of losses are included in "Miscellaneous non-operating deductions". The interest cost component of 
net periodic benefit cost is included in "Other interest".

The provisions in ASU 2017-07 were applied retrospectively for the income statement presentation of the service cost 
component and the other components of net benefit costs. The Company elected to apply the practical expedient and used 
the  amounts  previously  disclosed  in  2017  and  2016  as  the  estimation  basis  for  applying  the  retrospective  presentation 
requirements. 

The Company reclassified $8.2 million to "Operations and maintenance" in the Company’s Statement of Operations 
for the twelve months ended December 31, 2017 by increasing (i) "Investment and interest income, net" by $21.1 million, 
(ii) "Miscellaneous non-operating income" by $11.3 million, (iii) "Miscellaneous non-operating deductions" by $8.4 million,
and (iv) "Other interest" by $15.8 million. As a result of the reclassifications, "Operations and maintenance" increased to
$10.8 million in service cost from the $2.6 million in net periodic benefit cost previously reported.

The Company reclassified $7.0 million to "Operations and maintenance" in the Company’s Statement of Operations 
for the twelve months ended December 31, 2016 by increasing (i) "Investment and interest income, net" by $20.7 million, 
(ii) "Miscellaneous non-operating income" by $9.8 million, (iii) "Miscellaneous non-operating deductions" by $7.3 million,
and (iv) "Other interest" by $16.2 million. As a result of the reclassifications, "Operations and maintenance" increased to
$10.8 million in service cost from the $3.8 million in net periodic benefit cost previously reported.

Retirement Plans

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

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

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

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

92

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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

December 31,

2018

2017

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 (a) ...................................................
Interest cost.........................................................
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 .......................................................
Assumed expenses ..............................................
Fair value of plan assets at end of year........
Funded status at end of year ........................ $

$

361,989
9,086
12,013
(29,911)
(17,681)
335,496

304,389
(19,683)
7,300
(17,681)
(1,522)
272,803
(62,693) $

$

28,392
480
865
(1,087)
(1,931)
26,719

—
—
1,931
(1,931)
—
—
(26,719) $

$

337,768
8,156
12,196
20,829
(16,960)
361,989

269,766
44,283
7,300
(16,960)
—
304,389
(57,600) $

27,462
362
863
2,217
(2,512)
28,392

—
—
2,512
(2,512)
—
—
(28,392)

         _____________________

(a) Service cost for the Retirement Plan for 2018 excludes assumed expenses of $1,522 thousand for administrative

and investment expenses paid from plan assets during the year.

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

December 31,

2018

2017

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

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

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

— $

(62,693)
(62,693) $

(2,153) $
(24,566)
(26,719) $

— $

(57,600)
(57,600) $

(2,154)
(26,238)
(28,392)

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

December 31,

2018

2017

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

Retirement
Income
Plan
(335,496) $
(308,582)
272,803

Non-Qualified
Retirement
Plans

(26,719) $
(24,251)
—

Retirement
Income
Plan
(361,989) $
(329,279)
304,389

Non-Qualified
Retirement
Plans

(28,392)
(25,370)
—

93

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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

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

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

Years Ended December 31,

2018

2017

Retirement
Income
Plan
112,532
(16,942)
95,590

Non-Qualified
Retirement
Plans

$

$

9,300
(107)
9,193

$

$

Retirement
Income
Plan
109,215
(20,410)
88,805

Non-Qualified
Retirement
Plans

$

$

11,408
(146)
11,262

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

December 31,

2018

Non-Qualified

2017

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....

4.42%
4.5%

4.11%
N/A

4.45%
4.5%

3.77%
4.5%

3.40%
N/A

3.81%
4.5%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed and 
updated at each measurement date. The discount rate used to measure the fiscal year end obligation is based on a segmented 
spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the 
projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2018 retirement 
plans' projected benefit obligation by 11.7%. A 1% decrease in the discount rate would increase the December 31, 2018
retirement plans' projected benefit obligation by 14.4%.

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

Years Ended December 31,

2018

2017

2016

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

$

10,608
12,013
(21,076)

$

480
865
—

$

8,156
12,196
(19,189)

7,531
(3,467)

1,022
(39)

7,572
(3,467)

362
863
—

882
(39)

$

$

7,705
12,161
(18,879)

6,554
(3,467)

296
878
—

785
(39)

5,609

$

2,328

$

5,268

$

2,068

$

4,074

$

1,920

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

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

_____________________
(a) Service cost for the Retirement Plan for 2018 includes assumed expenses of $1,522 thousand for administrative and

investment expenses paid from plan assets during the year.

94

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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

2018

2017

2016

Years Ended December 31,

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

Retirement
Income
Plan

Non-Qualified
Retirement
Plans

10,848

$

(1,087) $

(4,265) $

2,217

$

8,644

$

1,266

(7,531)
3,467

(1,022)
39

(7,572)
3,467

(882)
39

(6,554)
3,467

(785)
39

6,784

$

(2,070) $

(8,370) $

1,374

$

5,557

$

520

Net (gain) loss ............................. $
Amortization of:

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

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

thousands): 

Years Ended December 31,

2018

2017

2016

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

12,393

$

258

$

(3,102) $

3,442

$

9,631

$

2,440

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

components of net periodic benefit cost during 2019 (in thousands): 

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

4,905
(3,467)

Retirement Income
Plan

Non-Qualified
Retirement Plans
763
$
(39)

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

twelve months ended December 31:

2018

Non-Qualified

2017

Non-Qualified

2016

Non-Qualified

Retirement
Income
Plan

Supplemental 
Retirement
Plan

Excess
Benefit
Plan

Retirement
Income
Plan

Supplemental 
Retirement
Plan

Excess
Benefit
Plan

Retirement
Income
Plan

Supplemental 
Retirement
Plan

Excess
Benefit
Plan

Discount rate

    Benefit 
    obligation.......
    Service cost....

    Interest cost....

Expected long-
term return on
plan assets..........
Rate of
compensation
increase ..............

3.77%

3.86%

3.40%

3.40% 3.81%

N/A

3.89%

2.84% 3.48%

4.30%

4.51%

3.70%

3.76% 4.35%

N/A

4.52%

2.94% 3.78%

4.57%

4.83%

3.86%

3.99% 4.63%

N/A

4.87%

3.04% 3.90%

7.5%

N/A

N/A

7.0%

N/A

N/A

7.0%

N/A

N/A

4.5%

N/A

4.5%

4.5%

N/A

4.5%

4.5%

N/A

4.5%

95

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The Company’s overall expected long-term rate of return on assets is 7.5% as of January 1, 2019, 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, 2018

49.0%

41.2%

9.8%

100.0%

The Retirement Plan invests the majority of its plan assets in common collective trusts which includes a diversified 
portfolio of domestic and international equity securities and fixed income securities. Alternative investments of the Retirement 
Plan are comprised of a real estate limited partnership, equity securities of real estate companies, primarily in real estate 
investment trusts and equity securities of listed companies involved in infrastructure activities. 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, real estate equity and infrastructure equity returns are based on estimates of long-term inflation rate, real rate of 
return, 10-year Treasury bond premium over cash, an expected equity risk premium, as well as other economic factors. Fixed 
income returns are based on maturity, long-term inflation, real rate of return and credit spreads. These assumptions also 
capture the expected correlation of returns between these asset classes over the long term.

The FASB guidance on disclosure for pension plans requires disclosure of fair value measurements of plan assets. To 
increase  consistency  and  comparability  in  fair  value  measurements,  the  FASB  guidance  on  fair  value  measurements 
established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels 
as follows:

•

•

•

Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets.
Prices of securities held in the mutual funds and underlying portfolios of the Retirement Plan are primarily obtained
from independent pricing services. These prices are based on observable market data. The Common Collective
Trusts are valued using the Net Asset Value ("NAV") provided by the administrator of the fund. The NAV price is
quoted on a restrictive market although the underlying investments are traded on active markets. The NAV used for
determining the fair value of the investments in the Common Collective Trusts have readily determinable fair values.
Accordingly, such fund values are categorized as Level 1.

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

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

96

—

—
—
—
—

—

—

—
—
—
—

—

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The fair value of the Company’s Retirement Plan assets at December 31, 2018 and 2017, 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):

Fair Value as of
December 31,
2018

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

1,911

$

1,911

$

— $

Description of Securities
Cash and Cash Equivalents ......................................................... $
Common Collective Trusts (a)

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

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

140,214
110,333
16,990
267,537
3,355
272,803

140,214
110,333
16,990
267,537

—
—
—
—

$

269,448

$

— $

Fair Value as of
December 31,
2017

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

1,582

$

1,582

$

— $

Description of Securities
Cash and Cash Equivalents ......................................................... $
Common Collective Trusts (a)

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

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

158,684
124,491
15,779
298,954
3,853
304,389

158,684
124,491
15,779
298,954

—
—
—
—

$

300,536

$

— $

 _____________________
(a) The  Common  Collective Trusts  are  invested  in  equity  and  fixed  income  securities,  or  a  combination  thereof. The
investment objective of each fund is to produce returns in excess of, or commensurate with, its predefined index.
(b) This investment is a commercial real estate partnership that purchases land, develops limited infrastructure and sells
it for commercial development. The Company was restricted from selling its partnership interest during the life of the
partnership, which spanned 7 years. Return on investment is realized as land is sold. The fair value of the limited
partnership interest in real estate is based on the NAV of the partnership which reflects the appraised value of the land.
The partnership term expired on June 30, 2016. Upon expiration, dissolution of the partnership commenced and, as a
result, the general partner of the partnership is attempting to sell the remaining inventory as soon as possible at the
highest pricing possible.

97

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The table below reflects the changes in the fair value of investments in the real estate limited partnership during the 

period (in thousands): 

Fair Value of
Investments in
Real Estate

Balances at December 31, 2016 .................................................................................. $
Sale of land...........................................................................................................
Unrealized loss in fair value.................................................................................
Balances at December 31, 2017 ..................................................................................
Sale of land...........................................................................................................
Unrealized loss in fair value.................................................................................
Balances at December 31, 2018 .................................................................................. $

6,991
(2,687)
(451)
3,853
(48)
(450)
3,355

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,  2018  and  2017. 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, 2018 and 2017.

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

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

thousands):

Retirement Income
Plan

2019 ........................................................................... $
2020 ...........................................................................
2021 ...........................................................................
2022 ...........................................................................
2023 ...........................................................................
2024-2028..................................................................

17,745
18,278
18,775
19,276
20,545
108,371

Non-Qualified
Retirement Plans
2,154
$
2,094
2,042
1,988
1,956
8,811

401(k) Defined Contribution Plans

The Company sponsors 401(k) defined contribution plans covering substantially all employees. The Company provides 
a 50 percent matching contribution up to 6 percent of the employee’s compensation for employees who are enrolled in the 
final average pay pension benefit of the Retirement Plan and a 100 percent matching contribution up to 6 percent of the 
employee's compensation for employees who are enrolled in the cash balance pension benefit of the Retirement Plan, subject 
to certain other limits and exclusions. Annual matching contributions made to the savings plans for the years 2018, 2017 and 
2016 were $4.6 million, $4.4 million, and $4.1 million, respectively. 

Other Post-retirement Benefits

The Company provides certain other post-retirement benefits, including health care benefits for retired employees and 
their  eligible  dependents  and  life  insurance  benefits  for  retired  employees  only  ("OPEB  Plan").  Substantially  all  of  the 
Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions 
from the Company are based on various factors such as the OPEB Plan's funded status, tax deductibility of contributions to 
the OPEB Plan, state and federal regulatory requirements, amounts requested from customers in the Company's Texas and 

98

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

New Mexico jurisdictions and the annual net periodic benefit cost of the OPEB Plan, as actuarially calculated. The assets of 
the OPEB Plan are primarily invested in institutional funds which hold equity securities, debt securities and cash equivalents 
and are managed by a professional investment manager appointed by the Company.

The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets and 

the funded status of the OPEB Plan (in thousands):

Change in benefit obligation:

Benefit obligation at end of prior year .................................................................................... $
Service cost (a) ........................................................................................................................
Interest cost..............................................................................................................................
Actuarial gain ..........................................................................................................................
Benefits paid from plan assets.................................................................................................
Benefits paid from corporate assets.........................................................................................
Retiree contributions ...............................................................................................................
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 from plan assets.................................................................................................
Retiree contributions ...............................................................................................................
Assumed expenses...................................................................................................................
Fair value of plan assets at end of year ............................................................................

Funded status at end of year ........................................................................................ $

December 31,

2018

2017

$

67,290
2,591
2,252
(9,295)
(3,003)
(141)
1,168
60,862

40,873
(2,997)
450
(3,003)
1,168
(204)
36,287
(24,575) $

73,515
2,236
2,723
(8,319)
(4,087)
—
1,222
67,290

39,115
4,173
450
(4,087)
1,222
—
40,873
(26,417)

_____________________
(a) Service cost for 2018 excludes assumed expenses of $204 thousand for administrative and investment expenses paid from

plan assets during the year.

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

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

— $

(24,575)

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

(24,575) $

—
(26,417)
(26,417)

December 31,

2018

2017

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

Net gain ............................................................. $
Prior service benefit...........................................

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

December 31,

2018
(36,890) $
(28,706)
(65,596) $

2017
(35,194)
(34,857)
(70,051)

99

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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

Discount rate at end of year.........................................................................................
Health care cost trend rates:

Initial ....................................................................................................................
Pre-65 medical.................................................................................................
Post-65 medical ...............................................................................................
Pre-65 drug ......................................................................................................
Post-65 drug.....................................................................................................
Ultimate................................................................................................................
Year ultimate reached (a)......................................................................................

December 31,

2018

2017

4.43%

3.79%

6.00%
4.50%
7.00%
8.50%
4.50%
2026

6.25%
4.50%
7.25%
10.00%
4.50%
2026

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

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed and 
updated at each measurement date. The discount rate used to measure the fiscal year end obligation is based on a segmented 
spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the 
projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2018 accumulated 
post-retirement benefit obligation by 13.4%. A 1% decrease in the discount rate would increase the December 31, 2018
accumulated post-retirement benefit obligation by 17.1%. 

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

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

Prior service benefit .......................................................................................
Net gain..........................................................................................................

Net periodic benefit cost......................................................................... $

Years Ended December 31,

2018

2017

2016

$

2,795
2,252
(2,435)

(6,151)
(2,166)
(5,705) $

$

2,236
2,723
(1,907)

(6,151)
(1,678)
(4,777) $

2,769
3,167
(1,835)

(3,901)
(2,374)
(2,174)

_____________________
(a) Service cost for 2018 includes assumed expenses of $204 thousand for administrative and investment expenses paid from

plan assets during the year.

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

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

Years Ended December 31,

2018

(3,863) $
—

2017
(10,586) $
—

2016

10,143
(32,697)

Prior service benefit .......................................................................................
Net gain..........................................................................................................
Total recognized in other comprehensive income................................................. $

6,151
2,166
4,454

$

6,151
1,678
(2,757) $

3,901
2,374
(16,279)

____________________
(a) During October 2016, the Company approved and communicated a plan amendment that resulted in a remeasurement
of the Company's OPEB Plan. Effective January 1, 2017, retirees and dependents that are less than 65 years of age are

100

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

offered a choice between a $1,000 and $2,250 deductible plan. Additionally, retirees and dependents that are 65 years 
of age or greater were covered by a fully insured Medicare advantage plan.

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

thousands):

Total recognized in net periodic benefit cost and other comprehensive income .. $

Years Ended December 31,

2018
(1,251) $

2017
(7,534) $ (18,453)

2016

The amount in accumulated other comprehensive income that is expected to be recognized as a component of net 

periodic benefit cost during 2019 is a prior service benefit of $5.2 million and a net gain of $2.3 million.

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

twelve months ended December 31:

Discount rate:

Benefit obligation................................................
Service cost .........................................................
Interest cost .........................................................
Expected long-term return on plan assets ................
Health care cost trend rates:

Initial.................................................................
Pre-65 medical .............................................
Post-65 medical............................................
Pre-65 drug...................................................
Post-65 drug .................................................
Ultimate ............................................................
Year ultimate reached (b)..................................

2018

2017

2016 (a)

January 1 -
September 30

October 1 -
December 31

3.79%
3.87%
3.38%
6.12%

6.25%
4.5%
7.25%
10.0%
4.5%
2026

4.37%
4.59%
3.76%
4.875%

6.5%
4.5%
7.5%
10.5%
4.5%
2026

4.59%
4.91%
3.86%
4.875%

7.0%
7.0%
7.0%
7.0%
4.5%
2026

3.75%
4.03%
3.15%
4.875%

7.0%
7.0%
7.0%
7.0%
4.5%
2026

_____________________
(a) The actuarial assumptions are evaluated by the Company at each measurement date. The OPEB Plan was remeasured at

October 1, 2016 due to a plan amendment.

(b) Pre-65 medical reaches the ultimate trend rate in 2025. Additionally, the Post-65 medical trend is assumed to be 4.50%

for all years into the future.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. The 
effect of a 1% change in these assumed health care cost trend rates would increase or decrease the December 31, 2018 benefit 
obligation by $9.9 million or $7.8 million, respectively. In addition, a 1% change in said rate would increase or decrease the 
aggregate  2018  service  and  interest  cost  components  of  the  net  periodic  benefit  cost  by  $1.2  million  or  $0.9  million, 
respectively.

101

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The Company's overall expected long-term rate of return on assets is 7.85%, as of January 1, 2019, on a pre-tax basis. 
The expected long-term rate of return on assets on an after-tax basis is 6.00% as of January 1, 2019. The trust's tax rate was 
assumed to be 35.0% at January 1, 2017 and 23.6% at January 1, 2019. The expected long-term rate of return is based on 
the after-tax weighted average of the expected returns on investments based upon the target asset allocation. The Company’s 
target allocations for the plan’s assets are presented below:

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

December 31, 2018

49.3%

34.3%

16.4%

100.0%

The OPEB Plan invests the majority of its plan assets in institutional funds which includes a diversified portfolio of 
domestic  and  international  equity  securities  and  fixed  income  securities. Alternative  investments  of  the  OPEB  Plan  are 
comprised of a real estate limited partnership and equity securities of real estate companies, primarily in real estate investment 
trusts. The alternative investments also include equity securities of a dynamic, diversified portfolio designed to capture market 
opportunities. The underlying allocations to various asset classes in this portfolio will shift over time, but the overall strategic 
allocation is as follows: 75% global equity, 15% marketable real assets and 10% global fixed income. The expected rates of 
return for the funds are assessed annually and are based on long-term relationships among major asset classes and the level 
of  incremental  returns  that  can  be  earned  by  the  successful  implementation  of  different  active  investment  management 
strategies. Equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium 
over cash, an expected equity risk premium, as well as other economic factors. Fixed income returns are based on maturity, 
long-term inflation, real rate of return and credit spreads. These assumptions also capture the expected correlation of returns 
between these asset classes over the long term.

The FASB guidance on disclosure for other post-retirement benefit plans requires disclosure of fair value measurements 
of plan assets. To increase consistency and comparability in fair value measurements, the FASB guidance on fair value 
measurements established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value 
into three levels as follows:

•

•

•

Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets.
Prices of securities held in the mutual funds and underlying portfolios of the Other Post-retirement Benefits Plan
are primarily obtained from independent pricing services. These prices are based on observable market data. The
institutional funds are valued using the NAV provided by the administrator of the fund. The NAV price is quoted
on  a  restrictive  market  although  the  underlying  investments  are  traded  on  active  markets.  The  NAV  used  for
determining  the  fair  value  of  the  investments  in  the  institutional  funds  have  readily  determinable  fair  values.
Accordingly, such fund values are categorized as Level 1.

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

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

102

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The fair value of the Company’s OPEB Plan assets at December 31, 2018 and 2017 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): 

Fair Value as of
December 31,
2018

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

1,353

$

1,353

$

— $

Description of Securities
Cash and Cash Equivalents ......................................................... $
Institutional Funds (a)

Equity funds.............................................................................
Fixed income funds .................................................................
Multi asset funds......................................................................
Real asset funds .......................................................................
Total Institutional Funds ......................................................
Limited Partnership Interest in Real Estate (b) ...........................

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

17,887
11,437
3,576
1,405
34,305
629
36,287

17,887
11,437
3,576
1,405
34,305

—
—
—
—
—

$

35,658

$

— $

Fair Value as of
December 31,
2017

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

809

$

809

$

— $

Description of Securities
Cash and Cash Equivalents ......................................................... $
Institutional Funds (a)

Equity funds.............................................................................
Fixed income funds .................................................................
Multi asset funds......................................................................
Real asset funds .......................................................................
Total Institutional Funds ......................................................
Limited Partnership Interest in Real Estate (b) ...........................

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

19,862
13,686
4,137
1,657
39,342
722
40,873

19,862
13,686
4,137
1,657
39,342

—
—
—
—
—

$

40,151

$

— $

 ___________________
(a) The institutional funds are invested in equity or fixed income securities, or a combination thereof. The investment

objective of each fund is to produce returns in excess of, or commensurate with, its predefined index.

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

103

—

—
—
—
—
—

—

—

—
—
—
—
—

—

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

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

Fair Value of
Investments  in
Real Estate

Balance at December 31, 2016......... $
Sale of land .................................
Unrealized loss in fair value .......
Balance at December 31, 2017.........
Sale of land .................................
Unrealized loss in fair value .......
Balance at December 31, 2018......... $

1,311
(504)
(85)
722
(9)
(84)
629

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,  2018  and  2017. 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, 2018 and 2017.

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

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

thousands): 

2019 .................................................................................. $
2020 ..................................................................................
2021 ..................................................................................
2022 ..................................................................................
2023 ..................................................................................
2024-2028 .........................................................................

2,145
2,542
2,719
2,869
2,999
16,803

Annual Short-Term Incentive Plan

The Annual Short-Term Incentive Plan ("Incentive Plan") provides for the payment of cash awards to eligible Company 
employees, including each of its named executive officers. Payment of awards is based on the achievement of performance 
measures  reviewed  and  approved  by  the  Company’s  Board  of  Directors’  Compensation  Committee.  Generally,  these 
performance measures are based on meeting certain financial, operational and individual performance criteria. The financial 
performance goals are based on specified levels of earnings and certain O&M expenses. The operational performance goals 
are based on reliability and customer satisfaction. If a minimum level of earnings is not attained, no amounts will be paid 
under the Incentive Plan, unless the Compensation Committee determines otherwise. In 2018, the Company reached the 
required levels of earnings, certain O&M expenses, reliability and customer satisfaction goals for an incentive payment of 
$11.0 million. In 2017 and 2016, the Company achieved required levels of similar goals for incentive payments of $9.7 
million and $12.5 million, respectively. 

104

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

O.

Franchises and Significant Customers

Franchises 

The Company operates under franchise agreements with several cities in its service territory, including one with El Paso, 
Texas, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve 
its customers within El Paso. Pursuant to the El Paso franchise agreement, the Company pays to the City of El Paso, on a quarterly 
basis, a fee equal to 5.00% 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 that amount has since been adjusted by two amendments. 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. The 2018 amendment, approved on March 20, 2018, and applicable to bills issued on or after October 1, 2018, increased 
the dedicated incremental fee by 1.00% of gross revenues and extended the term of the franchise agreement by 30 years. 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, 2060.

The Company does not have a written franchise agreement with Las Cruces, New Mexico, the second largest city in its 
service territory. The Company utilizes public rights-of-way necessary to service its customers within Las Cruces under an implied 
franchise pursuant to state law 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. 

The Company also maintains franchise agreements with other municipalities, and applicable counties, within its service 

territories. 

Military Installations 

The  Company  serves  HAFB,  White  Sands  Missile  Range  ("White  Sands")  and  Fort  Bliss.  These  military  installations 
represent approximately 2.6% of the Company's annual retail revenues. In July 2014, the Company signed an agreement with 
Fort Bliss under which Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company 
serves White Sands under the applicable New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under 
which the Company provides retail electric service and limited wheeling services to HAFB under the applicable New Mexico 
tariffs. As stated in the contract, HAFB will purchase the full output of a Company-owned 5 MW solar facility upon its completed 
construction, which occurred on October 18, 2018. HAFB's other power requirements are provided under the applicable New 
Mexico tariffs with limited wheeling services under the contract. 

105

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

P.

Financial Instruments and Investments

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

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

December 31,

2018

2017

Carrying
Amount

Estimated
Fair Value

Carrying
Amount

Estimated
Fair Value

Pollution Control Bonds .............................................................. $
Senior Notes (1)...........................................................................
RGRT Senior Notes (1) (2)..........................................................
RCF (2)........................................................................................

157,769
1,117,943
109,507
49,207
Total............................................................................... $ 1,434,426

$

161,917
1,244,310
111,440
49,207
$ 1,566,874

$

157,676
993,426
44,886
173,533
$ 1,369,521

$

169,186
1,211,922
47,070
173,533
$ 1,601,711

 __________________
(1) On June 28, 2018, the Company issued $125 million in aggregate principal amount of 4.22% Senior Notes due August 15,
2028 and guaranteed the issuance by the RGRT of $65 million in aggregate principal amount of 4.07% Senior Guaranteed
Notes due August 15, 2025. See Part II, Item 8, Financial Statements and Supplementary Data, Note J of Notes to Financial
Statements.

(2) Nuclear fuel financing, as of December 31, 2018 and December 31, 2017, is funded through $110 million and $45 million
RGRT Senior Notes and $26.2 million and $88.5 million, respectively under the RCF. As of December 31, 2018, $23 million
was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2017, $85.0 million
was  outstanding  under  the  RCF  for  working  capital  or  general  corporate  purposes. The  interest  rate  on  the  Company’s
borrowings under the RCF is reset throughout the period reflecting current market rates. Consequently, the carrying value
approximates fair value.

Treasury Rate Locks. The Company entered into treasury rate lock agreements in 2005 to hedge against potential movements
in the treasury reference interest rate pending the issuance of the 6% Senior Notes. The treasury rate lock agreements met the 
criteria for hedge accounting and were designated as a cash flow hedge. In accordance with cash flow hedge accounting, the 
Company recorded the loss associated with the fair value of the cash flow hedge, net of tax, as a component of accumulated other 
comprehensive loss and amortizes the accumulated comprehensive loss to earnings as interest expense over the life of the 6% 
Senior Notes. In 2019, approximately $0.6 million of this accumulated other comprehensive loss item will be reclassified to interest 
expense.

Contracts  and  Derivative  Accounting.  The  Company  uses  commodity  contracts  to  manage  its  exposure  to  price  and 
availability  risks  for  fuel  purchases  and  power  sales  and  purchases  and  these  contracts  generally  have  the  characteristics  of 
derivatives. The Company does not trade or use these instruments with the objective of earning financial gains on the commodity 
price fluctuations. The Company has determined that all such contracts outstanding at December 31, 2018, except for certain 
natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the "normal purchases 
and normal sales" exception provided in the FASB guidance for accounting for derivative instruments and hedging activities, and, 
as such, were not required to be accounted for as derivatives.

106

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Marketable Securities. The Company’s marketable securities, included in the NDT in the balance sheets, are reported at fair 
value, which was $276.9 million and $286.9 million at December 31, 2018 and 2017, respectively. The investments in the NDT 
are classified as available for sale debt securities, equity securities and cash and cash equivalents. These investments are recorded 
at their estimated fair value in accordance with FASB guidance for certain investments in debt and equity securities. On January 
1,  2018,  the  Company  adopted ASU  2016-01,  Financial  Instruments-Overall,  which  eliminates  the  requirements  to  classify 
investments in equity securities with readily determinable fair values as trading or available for sale and requires entities to recognize 
changes in fair value for these securities in net income as reported in the Statements of Operations. ASU 2016-01 requires a 
modified-retrospective approach and therefore, comparative information has not been restated and continues to be reported under 
the accounting standards in effect for those periods.

The reported fair values include gross unrealized losses on securities classified as available for sale whose impairment the 
Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, 
aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position 
(in thousands): 

December 31, 2018

Less than 12 Months

12 Months or Longer

Total

Fair
Value

Unrealized
Losses

Fair
Value

Unrealized
Losses

Fair
Value

Unrealized
Losses

Description of Securities (1):
Federal Agency Mortgage Backed Securities ....... $
U.S. Government Bonds .......................................
Municipal Debt Obligations..................................
Corporate Debt Obligations ..................................

6,187
4,005
3,100
22,259
Total............................................................... $ 35,551

$

$

 ____________________
(1)

Includes approximately 156 securities.

(36) $ 14,567
(9)
36,615
(74)
9,037
(763)
11,231
(882) $ 71,450

$

$

(1,663)
(723)
(731)

(510) $ 20,754
40,620
12,137
33,490
(3,627) $ 107,001

$

$

(546)
(1,672)
(797)
(1,494)
(4,509)

December 31, 2017

Less than 12 Months

12 Months or Longer

Total

Fair
Value

Unrealized
Losses

Fair
Value

Unrealized
Losses

Fair
Value

Unrealized
Losses

Description of Securities (2):
Federal Agency Mortgage Backed Securities ....... $
U.S. Government Bonds .......................................
Municipal Debt Obligations..................................
Corporate Debt Obligations ..................................
Total Debt Securities......................................
Domestic Equity Securities ...................................

4,700
28,866
4,290
10,685
48,541
962
Total........................................................ $ 49,503

$

$

 ______________________
(2)

Includes approximately 146 securities.

(46) $ 10,099
(416)
18,186
(73)
9,736
(107)
4,475
(642)
42,496
(210)
—
(852) $ 42,496

$

$

(165) $ 14,799
(969)
47,052
(742)
14,026
(331)
15,160
(2,207)
91,037
962
—
(2,207) $ 91,999

$

$

(211)
(1,385)
(815)
(438)
(2,849)
(210)
(3,059)

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

107

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

For the twelve months ended December 31, 2018, 2017 and 2016, the Company recognized other than temporary impairment 

losses on its available-for-sale securities as follows (in thousands):

Unrealized holding losses included in pre-tax income ......................................... $

— $

— $

(352)

2018

2017

2016

Investments categorized as available for sale securities also include gross unrealized gains which have not been recognized 
in the Company's net income. The table below presents the unrecognized gross unrealized gains and the fair value of these securities, 
aggregated by investment category (in thousands): 

December 31, 2018

December 31, 2017

Fair
Value

Unrealized
Gains

Fair
Value

Unrealized
Gains

Description of Securities:
Federal Agency Mortgage Backed Securities.............................. $
U.S. Government Bonds..............................................................
Municipal Debt Obligations ........................................................
Corporate Debt Obligations.........................................................
Total Debt Securities .....................................................
Domestic Equity Securities .........................................................
International Equity Securities ....................................................
Cash and Cash Equivalents .........................................................

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

9,959
6,987
1,952
8,283
27,181
—
—
—
27,181

$

$

176
149
120
222
667
—
—
—
667

$

$

5,933
11,129
2,558
19,514
39,134
120,065
28,804
6,864
194,867

$

$

203
256
109
1,067
1,635
45,587
5,908
—
53,130

The Company’s marketable securities include investments in mortgage backed securities, municipal, corporate and federal 
debt obligations. The contractual year for maturity for these available-for-sale securities as of December 31, 2018 is as follows 
(in thousands): 

Total

2019

2020 through
2023

2024 through 
2028

2029 and 
Beyond

Federal Agency Mortgage Backed Securities ........ $
U.S. Government Bonds.........................................
Municipal Debt Obligations ...................................
Corporate Debt Obligations ...................................

Total Available for Sale Debt Securities ........... $

30,713
47,607
14,089
41,773
134,182

$

$

— $

8,302
657
3,101
12,060

$

19
20,377
5,916
20,032
46,344

$

$

547
15,008
5,245
6,618
27,418

$

$

30,147
3,920
2,271
12,022
48,360

The Company's available for sale securities in the NDT are sold from time to time and the Company uses the specific 
identification basis to determine the amount to reclassify from AOCI into net income. The proceeds from the sale of these securities 
during the twelve months ended December 31, 2018, 2017, and 2016 and the related effects on pre-tax income are as follows (in 
thousands): 

Proceeds from sales or maturities of available-for-sale securities ........................ $
Gross realized gains included in pre-tax income .................................................. $
Gross realized losses included in pre-tax income .................................................

Gross unrealized losses included in pre-tax income .............................................
        Net gains (losses) included in pre-tax income .............................................. $

2018

2017

2016

25,955

$

$

17
(1,462)
—
(1,445) $

97,037

11,773
(1,147)
—
10,626

$

$

$

91,268

9,212
(1,220)
(352)
7,640

108

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

Upon the adoption of ASU 2016-01, Financial Instruments-Overall, on January 1, 2018, the Company records, on a modified-
retrospective basis, changes in fair market value for equity securities held in the NDT in the Statements of Operations. The unrealized 
gains and losses recognized during the twelve months ended December 31, 2018 and related effects on pre-tax income are as 
follows (in thousands):

December 31,
2018

Net gains and (losses) recognized on equity securities.......................................................... $

(11,522)

Less: Net gains and (losses) recognized on equity securities sold.........................................

7,079

Unrealized gains and (losses) recognized on equity securities still held at reporting date.... $

(18,601)

Fair  Value  Measurements. The  FASB  guidance  requires  the  Company  to  provide  expanded  quantitative  disclosures  for 
financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company's 
decommissioning trust investments and investments in debt securities which are included in deferred charges and other assets on 
the Balance Sheets. The Company has no liabilities that are measured at fair value on a recurring basis. The FASB guidance 
establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as 
follows:

•

•

•

Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial
assets utilizing Level 1 inputs include the NDT investments in active exchange-traded equity securities, mutual funds
and U.S. Treasury securities that are in a highly liquid and active market. The Institutional Funds are valued using the
NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying
investments  are  traded  on  active  markets.  The  NAV  used  for  determining  the  fair  value  of  the  Institutional  Funds-
International Equity investments have readily determinable fair values. Accordingly, such fund values are categorized as
Level 1.

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

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

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

109

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

The fair value of the NDT and investments in debt securities at December 31, 2018 and 2017, and the level within the three 

levels of the fair value hierarchy defined by the FASB guidance are presented in the table below (in thousands):

Description of Securities
Trading Securities:

Fair Value as  
of
December 31,
2018

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Investments in Debt Securities ....................................

Equity Securities:

Domestic......................................................................
International.................................................................
Total Equity Securities .........................................

Available for Sale Debt Securities:

Federal Agency Mortgage Backed Securities..............
U.S. Government Bonds..............................................
Municipal Debt Obligations ........................................
Corporate Debt Obligations.........................................
Total Available for Sale Debt Securities...............
Cash and Cash Equivalents .............................................
Total .....................................................................

$

$

$

1,656

111,325
24,540
135,865

30,713
47,607
14,089
41,773
134,182
6,858
276,905

$

$

$

— $

— $

1,656

$

111,325
24,540
135,865

— $
—
—

—
47,607
—
—
47,607
6,858
190,330

$

30,713
—
14,089
41,773
86,575
—
86,575

$

—
—
—

—
—
—
—
—
—
—

Description of Securities
Trading Securities:

Fair Value as  
of
December 31,
2017

Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)

Significant
Other
Observable
Inputs
(Level 2)

Significant
Unobservable
Inputs
(Level 3)

Investments in Debt Securities...................................... $

1,735

Available for sale:

Federal Agency Mortgage Backed Securities ............... $
U.S. Government Bonds ...............................................
Municipal Debt Obligations..........................................
Corporate Debt Obligations ..........................................
Subtotal, Debt Securities........................................
Domestic .......................................................................
International ..................................................................
Subtotal, Equity Securities.....................................
Cash and Cash Equivalents...............................................

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

20,732
58,181
16,584
34,674
130,171
121,027
28,804
149,831
6,864
286,866

$

$

$

— $

— $

1,735

— $

58,181
—
—
58,181
121,027
28,804
149,831
6,864
214,876

$

20,732
—
16,584
34,674
71,990
—
—
—
—
71,990

$

$

—
—
—
—
—
—
—
—
—
—

Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt securities classified 

as trading securities (in thousands): 

Balance at January 1 ....................................................................................................................... $
Net unrealized gains (losses) in fair value recognized in income (a)......................................
Balance at December 31 ................................................................................................................. $
_____________________
(a) These amounts are reflected in the Company's statements of operations as investment and interest income.

1,735
(79)
1,656

$

$

1,421
314
1,735

2018

2017

110

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable 
inputs  during  the  twelve-month  periods  ending  December 31,  2018  and  2017. There  were  no  purchases,  sales,  issuances  and 
settlements  related  to  the  assets  in  the  Level  3  fair  value  measurement  category  during  the  twelve-month  periods  ending 
December 31, 2018 and 2017.

Q.

Supplemental Statements of Cash Flows Disclosures

Years Ended December 31,

2018

2017

2016

(In thousands)

Cash paid for:

Interest on long-term debt and borrowing under the revolving credit
facility ............................................................................................................. $
Income tax paid, net........................................................................................

70,016

$

70,523

$

3,546

2,055

Non-cash investing and financing activities:

Sale of interest in Four Corners Generating Station (a) .................................

Changes in accrued plant additions ................................................................

Grants of restricted shares of common stock..................................................

Issuance of performance shares ......................................................................

—

1,075

1,039

1,499

—
(5,090)
1,171

932

69,990

2,328

27,720

4,789

1,235

—

______________

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

111

EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS

R.

Selected Quarterly Financial Data (Unaudited)

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

4th

2018 Quarters (1)

3rd

2nd

1st

4th (4)

3rd

2nd

1st

2017 Quarters

(In thousands except for share data)

Operating revenues (2) .............. $190,823
Operating income (3).................
15,113

Net income (loss).......................

(15,285)

Basic earnings per share:

$300,271

$236,796

$175,713

$196,149

$297,470

$251,843

$171,335

99,933

73,271

53,139

33,295

4,044
(6,966)

18,250

103,688

6,500

59,684

63,916

36,066

4,205
(3,989)

Net income (loss) ...............

(0.38)

1.80

0.82

(0.17)

0.16

1.47

0.89

(0.10)

Diluted earnings per share:

Net income (loss) ...............
Dividends declared per share of
common stock............................

(0.38)

1.79

0.82

(0.17)

0.16

1.47

0.89

(0.10)

0.360

0.360

0.360

0.335

0.335

0.335

0.335

0.310

 ________________
(1) Effective  January  1,  2018,  the  Company  implemented ASU  2016-01,  Financial  Instruments  -  Overall:  Recognition  and
Measurement of Financial Assets and Liabilities. As required by the new standard, changes in the fair values of the Company's
equity investments are recognized in earnings, whereas prior to 2018, such changes were recognized in accumulated other
comprehensive income.

(2) Operating  revenues  are  seasonal  in  nature,  with  the  peak  sales  periods  generally  occurring  during  the  summer  months.

Comparisons among quarters of a year may not represent overall trends and changes in operations.

(3) The Company implemented ASU 2017-07, Compensation - Retirement Benefits, in the first quarter of 2018, and as required
by the standard, reclassified certain amounts in the financial statements for 2017. See Part II, Item 8, Financial Statements
and Supplementary Data, Notes B and N of Notes to Financial Statements.

(4) For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2017 Texas Retail
Rate Case until it received the 2017 PUCT Final Order on December 18, 2017. Accordingly, it reported in the fourth quarter
of 2017 the cumulative effect of the 2017 PUCT Final Order, which related back to July 18, 2017. See Part II, Item 8, Financial
Statements and Supplementary Data, Note D of Notes to Financial Statements.

112

Item 9. 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 

None. 

Item 9A.  Controls and Procedures 

Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, 
including  our  chief  executive  officer  and  our  chief  financial  officer,  we  conducted  an  evaluation  pursuant  to  Rule 13a-15(b) 
under the Exchange Act of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Exchange Act. Based 
on  that  evaluation,  our  chief  executive  officer  and  our  chief  financial  officer  concluded  that,  as  of  December 31,  2018,  our 
disclosure controls and procedures are effective. 

Management’s Annual Report on Internal Control Over Financial Reporting. Management’s Annual Report on Internal 
Control over Financial Reporting is included herein under the caption "Management Report on Internal Control Over Financial 
Reporting" on page 46 of this Annual Report on Form 10-K. 

Changes  in  internal  control  over  financial  reporting.  There  were  no  changes  in  our  internal  control  over  financial 
reporting  in  connection  with  the  evaluation  required  by  paragraph  (d) of  the  Exchange  Act  Rules  13a-15  or  15d-15,  that 
occurred  during  the  quarter  ended  December 31,  2018,  that  materially  affected,  or  that  were  reasonably  likely  to  materially 
affect, our internal control over financial reporting. 

Item 9B.  Other Information 

None. 

The information set forth in Part III and Part IV of this Annual Report on Form 10-K has been omitted from this 

Annual Report to Shareholders. 

PART III and PART IV 

113 

 
 
 
 
 
 
 
 
 
 
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