EL PASO ELECTRIC
2017 ANNUAL REPORT
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EL PASO ELECTRIC
2017 ANNUAL REPORT
For El Paso Electric Company (“EE” or the “Company”),
2017 was a pivotal year as we built upon significant
achievements and continued our efforts to plan for the future
growth of the region we serve.
In December 2017, we received the final order in our 2017
Texas rate case, which provided for an annual non-fuel
base rate increase of $14.5 million. We were able to reach a
settlement in collaboration with the parties in the case that is
in the best interests of our customers and stakeholders alike.
Among the issues settled in the case was the establishment of
baseline revenue requirements for transmission and distribution
infrastructure. These baselines allow us to apply for the recovery
of transmission and distribution investments outside of a full
rate case proceeding, which helps in reducing regulatory lag
on our investments. We were also able to reach a compromise
with parties in the 2017 Texas rate case, including solar groups,
to implement a revised rate structure for new customers with
private distributed generation systems. Additionally, as part of
the settlement, we included a mechanism to provide the tax
savings from the reduction in the federal income tax rate to our
Texas customers.
Like other regulated electric utilities, we have been evaluating
the various impacts of the Tax Cuts and Jobs Act of 2017
and have been working with regulators to pass the tax savings
on to our customers. Although the tax reform legislation has
caused many challenges for the electric utility industry,
we remain focused on our credit quality and the strength of our
balance sheet.
To address our regional power needs over the next few years,
we issued an all-source request for proposal for resources in
June 2017. This request will help us prepare to meet the needs
of our continuously growing service territory and allow us to
plan for any potential retirements or life extensions of our older
generation resources.
In 2017, our customer base increased by 1.7%, which continues
to exceed the national average for customer growth. Also in
2017, we established a new native peak record of 1,935 MW.
We have established a new native peak record in 16 out of the
past 17 years, and since the year 2000, our native system peak
load has grown 67%.
As we continue to evolve and expand with our communities,
we strive to do so in a safe, cost-effective, reliable and
environmentally responsible manner. Among our biggest
accomplishments in 2017 was the completion of our Texas
Community Solar Facility. This three megawatt solar facility
is one of the largest utility-owned community solar facilities in
Texas, and generates renewable power for our Community Solar
Program, a volunteer-based program that was fully subscribed
within one month of accepting applications. Due to its popularity,
we are exploring ways to expand the program in Texas and
implement a similar program in New Mexico.
Also in 2017, we began construction of a five megawatt
dedicated solar facility at Holloman Air Force Base in New
Mexico, which will help the U.S. Air Force meet its renewable
and energy security goals. We look forward to finding innovative
ways to further grow our renewable energy portfolio in the future.
In May of 2017, our Board of Directors approved an increase
to the annual cash dividend of ten cents per share or
approximately 8%. We remain committed to moving towards
our goal of achieving an annual 55 to 65% dividend payout ratio
by the year 2020.
2017 was an impactful year in our community thanks to the
dedication of our over 1,100 employees. Throughout the course
of the year, we volunteered more than 8,800 hours of community
service to our local and regional organizations and schools.
The Company was also named the Texas Workforce Solutions’
Local Employer of Excellence for 2017, which was achieved due
to our work with STEAM programs and innovative internships.
This year, we will keep the issues that affect our community
and environment at the forefront of our work. This is why we
plan to publish our first sustainability report in 2018, which will
provide insight into the Company’s environmental, economic
and social impacts. The report will encompass the strategies
and opportunities that will help us strive to achieve our reliability
and resiliency goals.
We also plan to begin working in 2018 with our regional partners
on smart community initiatives, which may include the possible
deployment of advanced metering infrastructure in the future.
Advanced metering initiatives allow us to use the technology to
enhance grid resiliency and operations as well as expand our
services through smart pricing options, high usage alerts, and
online energy management. Ultimately, we want to collaborate
with regional leadership to expand economic development in
our community.
We look forward to continuing a tradition of excellent service and
community involvement over this next year as we strive to work
innovatively and safely to provide reliable electric power to those
we serve.
Mary E. Kipp
President and
Chief Executive Officer
Charles A. Yamarone
Chairman of the Board
of Directors
BOARD OF DIRECTORS & OFFICERS
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
OFFICERS
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.
James W. Harris
Managing Partner, OP Food Products, LLC,
a regional agricultural enterprise
Woodley L. Hunt
Executive Chairman,
Hunt Companies, Inc., a real estate
and infrastructure company
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
H. Wayne Soza
Vice President, Compliance
and Chief Risk Officer
Richard E. Turner
Vice President, Renewables Development
Mary E. Kipp
President and Chief Executive Officer
Russell G. Gibson
Vice President, Controller
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
William A. Stiller
Senior Vice President,
Public and Customer Affairs and
Chief Human Resources Officer
R. Clay Doyle
Vice President, Transmission
and Distribution
Eduardo Gutiérrez
Vice President, Public,
Government and Customer Affairs
David C. Hawkins
Vice President, Generation
and System Planning and Dispatch
Kerry B. Lore
Vice President, Customer Care
Victor F. Rueda
Vice President, Human Resources
and Community Outreach
James A. Schichtl
Vice President, Regulatory Affairs
Guillermo Silva, Jr.
Vice President, Community Outreach
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, 2017
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 and posted on its corporate Website, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). YES
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 126-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
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, 2017, the aggregate market value of the voting stock held by non-affiliates of the registrant was $2,069,728,021 (based
on the closing price as quoted on the New York Stock Exchange on that date).
As of January 31, 2018, there were 40,661,003 shares of the Company’s no par value common stock outstanding.
Portions of the registrant’s definitive Proxy Statement for the 2018 annual meeting of its shareholders are incorporated by reference
DOCUMENTS INCORPORATED BY REFERENCE
into Part III of this report.
The following abbreviations, acronyms or defined terms used in this report are defined below:
DEFINITIONS
Abbreviations, Acronyms or Defined Terms
Terms
ANPP Participation Agreement..........
Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as
amended
APS.....................................................
Arizona Public Service Company
ASU....................................................
Accounting Standards Update
Company ............................................
Copper ................................................ The Company's Copper Power Station
DOE....................................................
United States Department of Energy
El Paso Electric Company
El Paso................................................
City of El Paso, Texas
FASB ..................................................
Financial Accounting Standards Board
FERC..................................................
Federal Energy Regulatory Commission
Fort Bliss ............................................
Fort Bliss, the United States Army post next to El Paso, Texas
Four Corners....................................... Four Corners Generating Station
GHG ................................................... Greenhouse gas
HAFB ................................................. Holloman Air Force Base
IRS......................................................
Internal Revenue Service
kV .......................................................
Kilovolt(s)
kW ......................................................
Kilowatt(s)
kWh ....................................................
Kilowatt-hour(s)
Las Cruces ..........................................
MPS.................................................... The Company's Montana Power Station
MW.....................................................
City of Las Cruces, New Mexico
Megawatt(s)
MWh...................................................
Megawatt-hour(s)
Net dependable generating
capability ............................................
The maximum load net of plant operating requirements that a generating plant can supply
under specified conditions for a given time interval, without exceeding approved limits
of temperature and stress
Newman ............................................. The Company's Newman Power Station
NMPRC..............................................
New Mexico Public Regulation Commission
NRC....................................................
Nuclear Regulatory Commission
Palo Verde...........................................
Palo Verde Participants.......................
Palo Verde Generating Station
Those utilities that share in power and energy entitlements, and bear certain allocated
costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement
PNM ...................................................
Public Service Company of New Mexico
PUCT..................................................
Public Utility Commission of Texas
RGEC .................................................
Rio Grande Electric Cooperative
Rio Grande Resources Trust
RGRT..................................................
Rio Grande ......................................... The Company's Rio Grande Power Station
TCJA................................................... The Federal Tax Cuts and Jobs Act of 2017
TEP.....................................................
White Sands........................................ White Sands Missile Range
Tucson Electric Power Company
(i)
TABLE OF CONTENTS
Item
Description
Page
PART I
1 Business .......................................................................................................................................................................
1
1A Risk Factors ................................................................................................................................................................. 17
1B Unresolved Staff Comments ........................................................................................................................................ 24
2 Properties ..................................................................................................................................................................... 24
3 Legal Proceedings ........................................................................................................................................................ 24
4 Mine Safety Disclosures .............................................................................................................................................. 24
PART II
5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ... 25
6 Selected Financial Data ................................................................................................................................................ 27
7 Management’s Discussion and Analysis of Financial Condition and Results of Operations ....................................... 28
7A Quantitative and Qualitative Disclosures About Market Risk ..................................................................................... 49
8 Financial Statements and Supplementary Data ............................................................................................................ 51
9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ....................................... 112
9A Controls and Procedures .............................................................................................................................................. 112
9B Other Information ........................................................................................................................................................ 112
PART III ................................................................................................................................................................. 112
PART IV ................................................................................................................................................................. 112
(ii)
FORWARD-LOOKING STATEMENTS
Certain matters discussed in this Annual Report on Form 10-K, other than statements of historical fact, are "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E
of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Forward-looking statements often include words like
we "believe", "anticipate", "target", "project", "expect", "predict", "pro forma", "estimate", "intend", "will", "is designed to", "plan"
and words of similar meaning, or are indicated by the Company's discussion of strategies or trends. Forward-looking statements
describe the Company's future plans, objectives, expectations or goals. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, no assurances can be given that these expectations will prove to be
correct. Such statements address future events and conditions and include, but are not limited to:
•
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capital expenditures,
earnings,
liquidity and capital resources,
ratemaking/regulatory matters,
litigation,
accounting matters, including accounting for taxes,
possible corporate restructurings, acquisitions and dispositions,
compliance with debt and other restrictive covenants,
interest rates and dividends,
environmental matters,
nuclear operations,
operation of the Company's generating units and its transmission and distribution systems, and
the overall economy of our service area.
These forward-looking statements are based on assumptions and analyses in light of the Company's experience and perception
of historical trends, current conditions, expected future developments and other factors the Company believes were appropriate
in the circumstances when the statements were made. Forward-looking statements by their nature involve substantial risks and
uncertainties that could significantly impact expected results, and actual future results could differ materially from those described
in such statements. While it is not possible to identify all factors, the Company continues to face many risks and uncertainties.
Factors that would cause or contribute to such differences include, but are not limited to:
•
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•
•
actions of the Company's regulators,
the Company's ability to fully and timely recover its costs and earn a reasonable rate of return on its invested
capital through the rates that it is permitted to charge,
rates, cost recovery mechanisms and other regulatory matters including the ability to recover fuel costs on
a timely basis,
the ability of the Company's operating partners to maintain plant operations and manage operation and
maintenance costs at the Palo Verde Generating Station ("Palo Verde"), including costs to comply with any
new or expanded regulatory or environmental requirements,
reductions in output at generation plants operated by the Company,
the size of the Company's construction program and its ability to complete construction on budget and on
time,
the Company's reliance on significant customers,
the credit worthiness of the Company's customers,
unscheduled outages of generating units including outages at Palo Verde,
changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging
competing services and technologies, including distributed generation,
(iii)
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•
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•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
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•
individual customer groups, including distributed generation customers, may not pay their full cost of
service, and other customers may or may not be required to pay the difference,
changes in, and the assumptions used for, pension and other post-retirement and post-employment benefit
liability calculations, as well as actual and assumed investment returns on pension plan and other post-
retirement plan assets,
the impact of changing cost escalation and other assumptions on the Company's nuclear decommissioning
liability for Palo Verde, as well as actual and assumed investment returns on decommissioning trust fund
assets,
disruptions in the Company's transmission system, and in particular the lines that deliver power from its
remote generating facilities,
the sufficiency of the Company's insurance coverage, including availability, cost, coverage and terms,
electric utility deregulation or re-regulation,
regulated and competitive markets,
ongoing municipal, state and federal activities,
cuts in military spending or prolonged shutdowns of the federal government that reduce demand for the
Company's services from military and governmental customers,
political, legislative, judicial and regulatory developments,
homeland security considerations, including those associated with the U.S./Mexico border region and the
energy industry,
changes in environmental laws and regulations and the enforcement or interpretation thereof, including
those related to air, water or greenhouse gas ("GHG") emissions or other environmental matters,
economic, commercial bank, financial and capital market conditions,
actions by credit rating agencies,
changes in accounting requirements and other accounting matters,
changing weather trends and the impact of severe weather conditions,
possible physical or cyber attacks, intrusions or other catastrophic events,
the impact of lawsuits filed against the Company,
the impact of changes in interest rates or rates of inflation,
Texas, New Mexico and electric industry utility service reliability standards,
uranium, natural gas, oil and wholesale electricity prices and availability,
possible income tax and interest payments as a result of audit adjustments proposed by the Internal Revenue
Service ("IRS") or state taxing authorities,
the impact of recent changes to U.S. tax laws,
the impact of U.S. health care reform legislation,
the effectiveness of the Company's risk management activities,
loss of key personnel, the Company's ability to recruit and retain qualified employees and the Company's
ability to successfully implement succession planning, and
other circumstances affecting anticipated operations, sales and costs.
These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is
included in this document under the headings "Risk Factors" and "Management’s Discussion and Analysis of Financial Condition
and Results of Operations –Summary of Critical Accounting Policies and Estimates" and "Management’s Discussion and Analysis
of Financial Condition and Results of Operations –Liquidity and Capital Resources." This Annual Report on Form 10-K should
be read in its entirety. Management cautions against putting undue reliance on forward-looking statements or projecting any future
results based on such statements or present or prior earnings levels. Any forward-looking statement speaks only as of the date
(iv)
such statement was made, and the Company is not obligated to update any forward-looking statement to reflect events or
circumstances after the date on which such statement was made, except as required by applicable laws or regulations.
(v)
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 2,082 MW. For the year ended
December 31, 2017, the Company’s energy sources consisted of approximately 49% nuclear fuel, 36% natural gas, 15% purchased
power and less than 1% generated by Company-owned solar photovoltaic panels. The Company continues to expand its portfolio
of renewable energy sources, particularly solar photovoltaic generation. As of December 31, 2017, the Company had power
purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources – Purchased Power").
The Company serves approximately 417,900 residential, commercial, industrial, public authority and wholesale customers.
The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing
approximately 64% and 11%, respectively, of the Company’s retail revenues for the year ended December 31, 2017). In addition,
the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public
authority and other large retail customers of the Company include United States military installations, such as Fort Bliss in Texas
and White Sands Missile Range ("White Sands") and Holloman Air Force Base ("HAFB") in New Mexico, an oil refinery, several
medical centers, two large universities and a steel production facility.
The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone:
915-543-5711). The Company was incorporated in Texas in 1901. As of January 31, 2018, the Company had approximately
1,100 employees, 38% of whom are covered by a collective bargaining agreement.
The Company makes available free of charge through its website, www.epelectric.com, its Annual Report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statement and all amendments to those reports as soon as
reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission
("SEC"). In addition, copies of this Annual Report on Form 10-K will be made available free of charge upon written request. The
SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that
file electronically with the SEC. The address of that site is www.sec.gov. The information on the Company's website is not
incorporated by reference into this Annual Report on Form 10-K.
As of December 31, 2017, the Company’s net dependable generating capability of approximately 2,082 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
________________
* During summer peak period.
Primary Fuel
Type
Natural Gas
Nuclear
Natural Gas
Natural Gas
Natural Gas
Solar
Location
El Paso, Texas
100%
15.8% Wintersburg, Arizona
100% Sunland Park, New Mexico
100%
100%
100%
El Paso, Texas
El Paso, Texas
Culberson/El Paso Counties,
Texas; Dona Ana County,
New Mexico
Company's
Share of Net
Dependable
Generating
Capability*
(MW)
Company
Ownership
Interest
752
633
276
354
64
3
2,082
1
Palo Verde
The Company owns an interest, along with six other utilities, in the three nuclear generating units and common facilities
("Common Facilities") at Palo Verde. Arizona Public Service Company ("APS") serves as operating agent for Palo Verde, and
under the Arizona Nuclear Power Project Participation Agreement ("ANPP Participation Agreement"), the Company has limited
ability to influence operations and costs at Palo Verde.
• Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license
from the Nuclear Regulatory Commission ("NRC"). The NRC issued full power operating licenses for Unit 1
in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and issued renewed operating licenses for each
of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and
November 2047, respectively.
• Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its
share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities,
through the term of their respective operating licenses. In 2017, the Palo Verde Participants approved the 2016
Palo Verde decommissioning study (the "2016 Study"), which estimated that the Company must fund
approximately $432.8 million (stated in 2016 dollars) to cover its share of decommissioning costs. At
December 31, 2017, the Company's decommissioning trust fund had a balance of $286.9 million. Although the
2016 Study was based on the latest available information, there can be no assurance that decommissioning cost
estimates will not increase in the future or that regulatory requirements will not change.
•
Spent Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the
"NWPA"), the United States Department of Energy ("DOE") is legally obligated to accept and dispose of all
spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The
DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive
Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear
fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a
second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the
DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30,
2011. On August 18, 2014, APS and the DOE entered into a settlement agreement stipulating to a dismissal of
the lawsuit. Pursuant to the terms of the August 18, 2014 settlement agreement, APS files annual claims for the
period July 1 of the then-previous year to June 30 of the then-current year. The settlement agreement, as amended,
provides APS with a method for submitting claims and receiving recovery for costs incurred through December
31, 2016, which has been extended to December 31, 2019. The Company's share of costs recovered are presented
below (in thousands):
Amount Credited
to Customers
through Fuel
Period Credited
Costs Recovery Period
Amount Refunded
Adjustment Clauses
to Customers
January 2007 - June 2011
$
July 2011 - June 2014
July 2014 - June 2015
July 2015 - June 2016
9,076 $
6,643
1,884
1,779
7,944
5,759
1,581
1,432
September 2014
March 2015
March 2016
March 2017
On October 31, 2017, APS filed an $8.9 million claim for the period July 1, 2016 through June 30, 2017. The
Company's share of this claim is approximately $1.4 million. In February 2018, the DOE approved this claim.
Any reimbursement is anticipated to be received in the first half of 2018, and the majority of the reimbursement
received by the Company is expected to be credited to customers through the applicable fuel adjustment clauses.
• DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal
obligations by designing, licensing, constructing and operating a permanent geologic repository in Yucca
Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain
construction authorization application that was pending before the NRC. Several interested parties have
intervened in the NRC proceeding. Additionally, a number of interested parties have filed a variety of lawsuits
in different jurisdictions around the country challenging the DOE's authority to withdraw the Yucca Mountain
2
construction authorization application and NRC’s cessation of its review of the Yucca Mountain construction
authorization application. The cases have been consolidated into one matter at the U.S. Court of Appeals for the
District of Columbia Circuit (the "D.C. Circuit"). In August 2013, the D.C. Circuit ordered the NRC to resume
its review of the application with available appropriated funds.
On October 16, 2014, the NRC issued Volume 3 of the safety evaluation report developed as part of the Yucca
Mountain construction authorization application. This volume addresses repository safety after permanent
closure, and the issuance of Volume 3 is a key milestone in the Yucca Mountain licensing process. Volume 3
contains the NRC staff’s finding that the DOE’s repository design meets the requirements that apply after the
repository is permanently closed, including but not limited to the post-closure performance objectives in the
NRC’s regulations.
On December 18, 2014, the NRC issued Volume 4 of the safety evaluation report developed as part of the Yucca
Mountain construction authorization application. This volume covers administrative and programmatic
requirements for the repository. It documents the NRC staff’s evaluation of whether the DOE’s research and
development and performance confirmation programs, as well as other administrative controls and systems,
meet applicable NRC requirements. Volume 4 contains the NRC staff’s finding that most administrative and
programmatic requirements in NRC regulations are met, except for certain requirements relating to ownership
of land and water rights.
Publication of Volumes 3 and 4 does not signal whether or when the NRC might authorize construction of the
repository. The Company cannot predict when spent fuel shipments to the DOE will commence.
• Waste Confidence and Continued Storage. On June 8, 2012, the D.C. Circuit issued its decision on a challenge
by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent
disposal of high level nuclear waste and spent nuclear fuel. The petitioners challenged the NRC’s 2010 update
to the agency’s Waste Confidence Decision and temporary storage rule ("Waste Confidence Decision").
The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal
action, which, consistent with the National Environmental Policy Act ("NEPA"), requires either an environmental
impact statement or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that
the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded
the 2010 Waste Confidence Decision update for further action consistent with NEPA.
On September 6, 2012, the NRC Commissioners issued a directive to the NRC staff to proceed directly with
development of a generic environmental impact statement to support an updated Waste Confidence Decision.
The NRC Commissioners also directed the NRC staff to establish a schedule to publish a final rule and
environmental impact study within 24 months of September 6, 2012.
In September 2013, the NRC issued its draft Generic Environmental Impact Statement ("GEIS") to support an
updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental
effects of continued storage of spent nuclear fuel. Renamed the Continued Storage Rule, the NRC's decision
adopted the findings of the GEIS regarding the environmental impacts of storing spent fuel at any reactor site
after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed
in the environmental reviews for individual licenses. Although Palo Verde has not been involved in any licensing
actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing
actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its
June 2012 decision. The final Continued Storage Rule was subject to continuing legal challenges before the
NRC and the Court of Appeals. In June 2016, the D.C. Circuit issued its final decision, rejecting all remaining
legal challenges to the Continue Storage Rule. On August 8, 2016, the D.C. Circuit denied a petition for rehearing.
Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation ("ISFSI") to store all
of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December
2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will
be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding
the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will
evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the
fuel that will be irradiated during the period of extended operation.
The One-Mill Fee. In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear
Energy Institute challenged the DOE’s 2010 determination of the adequacy of the one tenth of a cent per kWh
3
fee (the "one-mill fee") paid by the nation’s commercial nuclear power plant owners pursuant to their individual
obligations under the Standard Contract. This fee was recovered by the Company through applicable fuel
adjustment clauses. In June 2012, the D.C. Circuit held that the DOE failed to conduct a sufficient fee analysis
in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the Secretary of the
DOE (the "Secretary") with instructions to conduct a new fee adequacy determination within six months. In
February 2013, upon completion of the DOE’s revised one-mill fee adequacy determination, the court reopened
the proceedings. On November 19, 2013, the D.C. Circuit ordered the Secretary to notify Congress of his intent
to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators, as he is required
to do pursuant to the NWPA and the court’s order. On January 3, 2014, the Secretary notified Congress of his
intention to suspend collection of the one-mill fee, subject to Congress’ disapproval and on May 16, 2014, the
DOE notified all commercial nuclear power plant operators, effective May 16, 2014, the one-mill fee was
suspended. Electricity generated at Palo Verde and sold on or after May 16, 2014 is no longer subjected to the
one-mill fee.
• NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. The NRC
regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The
NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the
agency to arrive at objective conclusions about a licensee's safety performance. Following the March 11, 2011
earthquake and tsunami in Japan, the NRC established a task force to conduct a systematic and methodical
review of NRC processes and regulations to determine whether the agency should make additional improvements
to its regulatory system. On March 12, 2012, the NRC issued the first regulatory requirements based on the
recommendations of the NRC's Near Term Task Force. With respect to Palo Verde, the NRC issued two orders
requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting
in the loss of power at plants and (2) enhancement of spent fuel pool instrumentation.
The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements.
Palo Verde has met the NRC's imposed deadlines for the installation of equipment to address these requirements.
Palo Verde has spent approximately $125.4 million (the Company's share is $19.8 million) on capital
enhancements related to these requirements as of December 31, 2017.
• Liability and Insurance Matters. The Palo Verde Participants have insurance for public liability resulting from
nuclear energy hazards, covered by primary liability insurance provided by commercial insurance carriers and
an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs
exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective
premium adjustments on a per incident basis up to $60.4 million, with an annual payment limitation of
approximately $9.0 million. The Palo Verde Participants also maintain $2.75 billion of "all risk" nuclear property
insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered
incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage
limit is $2.25 billion. In addition, the Company has secured insurance against portions of any increased cost of
generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo
Verde.
Fossil-Fueled Plants
The Newman Power Station ("Newman") consists of three conventional steam-electric generating units and two combined
cycle generating units. The station operates primarily on natural gas but the conventional steam-electric generating units can also
operate on fuel oil.
The Company's Rio Grande Power Station ("Rio Grande") consists of three conventional steam-electric generating units
and one aeroderivative unit that operate on natural gas.
The Company's Montana Power Station ("MPS") consists of four aeroderivative generating units which operate on natural
gas. The units can also operate on fuel oil.
The Company's Copper Power Station ("Copper") consists of a natural gas combustion turbine used primarily to meet peak
demand.
The Company owned a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners"). The Company
shared power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other
Four Corners participants. On July 6, 2016, the Company sold its interests in Four Corners for $32.0 million to 4C Acquisition,
LLC, an affiliate of APS ("APS's affiliate"), and Pinnacle West Capital Corporation ("Pinnacle West"), the parent company of APS
4
and APS's affiliate. No significant gain or loss was recorded for this sale. APS's affiliate assumed responsibility for all Four Corners
capital expenditures made after July 6, 2016, which assumption is guaranteed by Pinnacle West. In addition, APS's affiliate will
indemnify the Company against certain liabilities and costs related to the future operation of Four Corners, which indemnification
is guaranteed by Pinnacle West. See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note E of Notes
to Financial Statements for further discussions.
Solar Photovoltaic Facilities
The Company’s Texas Community solar facility, a 3 MW utility-scale solar plant located at MPS, began commercial operations
on May 31, 2017. The Company also owns six other solar photovoltaic facilities with a total capacity of 0.2 MW.
Transmission and Distribution Lines and Agreements
The Company owns, or has significant ownership interests in, four 345 kV transmission lines in New Mexico and Arizona
and three 500 kV lines in Arizona. These lines enable the Company to deliver its energy entitlements from its remote generation
at Palo Verde to its service area (pursuant to various transmission and power exchange agreements to which the Company is a
party). The Company also owns the transmission and distribution network within its New Mexico and Texas retail service area
and operates these facilities under franchise agreements with various municipalities. Pursuant to standards established by the North
American Electric Reliability Corporation and the Western Electricity Coordinating Council, the Company operates its transmission
system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service.
In addition to the transmission and distribution lines within our service territory, the Company's transmission network and
associated substations include the following:
Line
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 ("PNM") West Mesa Substation located near Albuquerque,
New Mexico, to the Company's Arroyo Substation located near Las Cruces, New Mexico.
(3) Runs from TEP's Greenlee Substation located near Duncan, Arizona to Newman.
(4) Runs from the Company's and PNM's high voltage direct current terminal at the Eddy County Substation near
Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico.
(5) Represents two 45-mile, 500 kV lines running from Palo Verde to the Westwing Substation located northwest of
Phoenix near Peoria, Arizona.
(6) Runs from Palo Verde to the Jojoba Substation located near Gila Bend, Arizona, then to the Kyrene Substation
located near Tempe, Arizona.
5
Environmental Matters
General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and GHG
emissions, water discharges, soil and water quality, waste management and disposal, natural resources and other environmental
matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and requirements can
result in actions by authorities or other third parties that might seek to impose on the Company administrative, civil and/or criminal
penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup
liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation, or the
introduction of new laws and regulations, and, as a result, the Company may face additional capital and operating costs to comply.
Certain key environmental issues, laws and regulations facing the Company are described further below.
In March 2017, the Company entered into a Compliance Agreement ("Compliance Agreement") with the Texas
Commission on Environmental Quality under the Texas Environmental, Health and Safety Audit Privilege Act to address certain
water and waste compliance issues associated with the integrity of the synthetic liner of the evaporation pond at the Company’s
Newman Generating Station. The Company has initiated a capital project to extend the life of evaporation pond and in doing so
will complete its obligation of the Compliance Agreement.
Air Emissions. The U.S. Clean Air Act ("CAA"), associated regulations and comparable state and local laws and regulations
relating to air emissions impose, among other obligations, limitations on pollutants generated during the operations of the Company's
facilities and assets, including sulfur dioxide ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury.
National Ambient Air Quality Standards ("NAAQS"). Under the CAA, the EPA sets NAAQS for six criteria pollutants
considered harmful to public health and the environment, including PM, NOx, carbon monoxide ("CO"), ozone and SO2. NAAQS
must be reviewed by the EPA at five-year intervals. In 2010, the EPA tightened the NAAQS for both nitrogen dioxide ("NO2")
and SO2. The EPA is considering a 1-hour secondary NAAQS for NO2 and SO2. In January 2013, the EPA tightened the primary
annual NAAQS for fine PM. On October 1, 2015, the EPA released a final rule tightening the primary and secondary NAAQS for
ground-level ozone from its 2008 standard levels of 75 parts per billion ("ppb") to 70 ppb.The EPA may designate the areas in
which we operate as nonattainment. For example, in December 2017, EPA proposed to designate southern Dona Ana County, New
Mexico, as a nonattainment area. States that contain any areas designated as nonattainment, and any tribes that choose to do so,
will be required to complete development of implementation plans in the 2020-2021 timeframe. Most nonattainment areas are
expected to have until 2020 or 2023 to meet the primary (health) standard, with the exact attainment date varying based on the
ozone level in the area. The Company continues to evaluate what impact these final and proposed NAAQS could have on its
operations. If the Company is required to install additional equipment to control emissions at its facilities, the NAAQS, individually
or in the aggregate, could have a material impact on its operations and financial results.
Other Laws and Regulations and Risks. The Company sold its interest in Four Corners to APS's affiliate on July 6, 2016 at
the expiration of the 50-year participation agreement. As of the closing date of the sale, the Company’s environmental liabilities
associated with Four Corners were limited to conditions that existed at the time of the sale and further limited to the portion thereof
for which the Company would have been financially responsible if Four Corners had fully ceased operation on July 6, 2016.
Pursuant to the terms of the Purchase and Sale Agreement, neither APS's affiliate nor APS assumed the Company's pre-closing
obligations under environmental laws with respect to its interest in Four Corners. The Company may be subject to certain future
claims under environmental laws and regulations as a former owner of Four Corners. The extent of such claims, if any, cannot be
predicted with certainty.
Climate Change. There has been a wide-ranging policy debate, at the local, state, national, and international levels, regarding
the impact of GHG and possible means for their regulation. Efforts continue to be made in the international community toward
the adoption of international treaties or protocols that would address global climate change issues. In April 2016, the United States
signed the Paris Agreement, which requires countries to review and "represent a progression" in their intended nationally determined
contributions, which set GHG emission reduction goals, every five years beginning in 2020. In August 2017, the United States
formally documented to the United Nations its intent to withdraw from the Paris Agreement. The earliest possible effective
withdrawal date from the Paris Agreement is November 2020.
The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting GHG
emissions, including carbon dioxide. In particular, the U.S. Congress has considered legislation to restrict or regulate GHG
emissions. In October 2015, the EPA published a rule establishing guidelines for states to regulate CO2 emissions from existing
power plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. The Company cannot at this
time determine the impact of the CPP, related proposals and legal challenges may have on our financial position, results of operations
or cash flows.
6
While a significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes
that its GHG emissions are low relative to electric power companies who rely more on coal-fired generation, current and future
legislation and regulation of GHG or any future related litigation could impose significant costs and/or operating restrictions on
the Company, reduce demand for the power the Company generates, and/or require the Company to purchase rights to emit GHG,
any of which could be material to the Company's business, reputation, financial condition or results of operations.
Climate change also has potential physical effects that could be relevant to the Company's business. In particular, climate
change could affect the Company's service area by causing higher temperatures, less winter precipitation and less spring runoff,
as well as by causing more extreme weather events. Such developments could change the demand for power in the region and
could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company
equipment. The Company believes that material effects on the Company's business or results of operations may result from the
physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by
governmental authorities, or both. Given the very significant remaining uncertainties regarding whether and how these issues will
be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible
to meaningfully quantify the costs of these potential impacts at present.
Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the
EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The
allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the
controls necessary under the CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under
Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. District
Court for New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S.
District Court for New Mexico entered the CAA Settlement Agreement. The agreement imposes a total civil penalty payable by
the co-owners of Four Corners collectively in the amount of $1.5 million, and it requires the co-owners to pay $6.7 million for
environmental mitigation projects. At December 31, 2017, the Company has accrued its remaining unpaid share of approximately
$0.2 million related to this matter.
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 and terminated purchased power agreements, the
costs of which are included in the table below.
The Company’s estimated cash construction costs for 2018 through 2022 are approximately $1.3 billion. Actual costs may
vary from the construction program estimates shown. Such estimates are under continuous review and subject to ongoing adjustment
and are updated periodically to reflect changed conditions.
By Year (1)(2)
(estimates in millions)
2018................................................... $
2019...................................................
2020...................................................
2021...................................................
2022...................................................
Total ........................................... $
236
238
278
298
253
1,303
By Function
(estimates in millions)
Production (1)(2) ........................ $
Transmission...............................
Distribution .................................
General........................................
551
183
430
139
Total ..................................... $
1,303
__________________________
(1) Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel."
(2) Estimated production costs consist of:
a.
$320 million for new generating capacity, primarily including:
i.
ii.
$305 million of construction costs from 2018 through 2022 for a 320 MW combined cycle
generating plant scheduled to be completed in 2023.
$13 million for two utility-scale solar energy generating facilities which would have a combined
maximum capacity of up to 7 MW.
b.
$231 million of other generation costs, including $184 million for Palo Verde.
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...............................................................
2017
2016
(percentage of total kWh energy mix)
2015
49%
36%
—%
15%
100%
49%
34%
2%
15%
100%
47%
34%
6%
13%
100%
Allocated fuel and purchased power costs are generally recoverable from customers in Texas and New Mexico pursuant to
applicable regulations. Historical fuel costs and revenues are reconciled periodically in proceedings before the Public Utility
Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC"). See "Regulation – Texas
Regulatory Matters" and "Regulation – New Mexico Regulatory Matters."
Nuclear Fuel
The nuclear fuel cycle for Palo Verde consists of the following stages: the mining and milling of uranium ore to produce
uranium concentrates, the conversion of the uranium concentrates to uranium hexafluoride ("conversion services"), the enrichment
of uranium hexafluoride ("enrichment services"), the fabrication of fuel assemblies ("fabrication services"), the utilization of the
fuel assemblies in the reactors, and the storage and disposal of the spent fuel.
Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in
connection with Palo Verde. The Palo Verde Participants are continually identifying their future nuclear fuel resource needs and
negotiating arrangements to fill those needs. The Palo Verde Participants have contracted for 100% of Palo Verde's requirements
for uranium concentrates through 2023 and 50% of its requirements for 2024 through 2025. The participants have contracted for
100% of Palo Verde's requirement for conversion services through 2021 and 46% of its requirements for 2022 through 2025. The
participants have also contracted for 100% of Palo Verde's requirement for enrichment services through 2020 and 20% of its
requirement for 2021 through 2026 and all of Palo Verde's requirement for fuel assembly fabrication services through 2024.
Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust
("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. As of December 31, 2017, RGRT
has $45 million aggregate principal amount borrowed in the form of senior notes. In August 2017, RGRT's $50 million Series B
4.47% Senior Notes matured and were paid utilizing funds borrowed under the revolving credit facility (the "RCF"). The Company
guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing requirements of RGRT are met
with a combination of the senior notes and short-term borrowings under the RCF.
Natural Gas
The Company manages its natural gas requirements through a combination of a long-term (greater than a year) supply
contract, several medium-term (greater than a month but less than one year) supply contracts and spot or short-term (daily to a
month) market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. Medium-
term and spot agreements are either fixed priced and/or index priced depending on the market. In 2017, the Company’s natural
gas requirements at Newman, Rio Grande and MPS were met with short-term, medium-term and long-term natural gas purchases
from various suppliers, and this practice is expected to continue in 2018. Interstate gas is delivered under a base firm transportation
contract. The Company has expanded its firm interstate transportation contract to include MPS. The Company anticipates it will
continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for Newman, Rio Grande
and MPS. The Company will continue to evaluate the availability of short-term natural gas supplies versus medium and long-term
supplies to maintain a reliable and economical supply for its local generating stations.
Natural gas for Newman and Copper is also supplied pursuant to a long-term intrastate natural gas contract that became
effective October 1, 2009 and continues through March 31, 2018. Beginning April 1, 2018, intrastate natural gas reservation and
storage for Newman, Copper and MPS will be provided through a new contract that will continue through March 31, 2028. Under
9
this new contract, intrastate gas supply will be sourced in the same manner as interstate gas, through a variety of long, medium
and short-term supply contracts.
Purchased Power
To supplement its own generation and operating reserve requirements, and to meet required renewable portfolio standards,
the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the
Company’s resource needs, the economics of the transactions and specific renewable portfolio requirements.
The Company has a firm 100 MW Power Purchase and Sale Agreement (the "Power Purchase and Sale Agreement") with
Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport"), pursuant to which Freeport will deliver energy to the
Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New
Mexico) and the Company will deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to the
contracted MW amount at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement.
The Power Purchase and Sale Agreement was approved by the Federal Energy Regulatory Commission ("FERC") and will continue
through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power
Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold thereunder. The parties
have agreed to increase the amount up to 125 MW through December 2018.
The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements.
Specifically, the Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar
photovoltaic project located in southern New Mexico, which began commercial operation in July 2011. In June 2015, the Company
entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement photovoltaic
modules. The Company also entered into a 20-year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all
of the output of a 20 MW solar photovoltaic plant built in southern New Mexico, which began commercial operation in August
2011. In addition, the Company has 25-year purchase power agreements to purchase all of the output of two additional solar
photovoltaic projects located in southern New Mexico, SunE EPE1, LLC (10 MW) and SunE EPE2, LLC (12 MW), which began
commercial operation in June 2012 and May 2012, respectively. In September 2017, Longroad Solar Portfolio Holdings, LLC
purchased SunE EPE1, LLC and in October 2017, Silicon Ranch Corporation purchased SunE EPE2, LLC with the Company's
consent per the terms of both purchase power agreements.
Furthermore, the Company has a 20-year purchase power agreement with Macho Springs Solar, LLC to purchase the entire
generation output delivered from the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico
which began commercial operation in May 2014. Finally, the Company has a 30-year purchase power agreement with Newman
Solar LLC to purchase the total output, which is approximately 10 MW, from a solar photovoltaic generation plant on land subleased
from the Company in proximity to Newman. This solar project began commercial operation in December 2014.
Other purchases of shorter duration were made during 2017 to supplement the Company's generation resources during planned
and unplanned outages, for economic reasons and to supply off-system sales.
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 ..............................................................................
Total non-fuel base revenues .................................................
Fuel revenues:
Recovered from customers during the period.........................................
Under (over) collection of fuel ...............................................................
New Mexico fuel in base rates................................................................
Total fuel revenues ........................................................................
Off-system sales:
Fuel cost..................................................................................................
Shared margins .......................................................................................
Retained margins ....................................................................................
Total off-system sales....................................................................
Other ..............................................................................................................
Total operating revenues........................................................ $
Number of customers (end of year) (1):
Residential......................................................................................................
Commercial and industrial, small ..................................................................
Commercial and industrial, large...................................................................
Other ..............................................................................................................
Total .......................................................................................
Average annual kWh use per residential customer ...............................................
Energy supplied, net, kWh (in thousands):
Years Ended December 31,
2016
2015
2017
$
$
287,884
198,799
38,403
97,890
622,976
2,730
625,706
218,380
(17,133)
—
201,247
46,258
11,055
1,673
58,986
30,858
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
38,933
5,632
1,137
45,702
32,591
886,936
363,987
41,741
49
5,285
411,062
7,748
246,265
187,436
40,411
91,244
565,356
2,455
567,811
127,765
(13,342)
72,129
186,552
52,406
11,048
1,362
64,816
30,690
849,869
358,819
40,367
49
5,261
404,496
7,763
Generated .......................................................................................................
Purchased and interchanged...........................................................................
Total .......................................................................................
8,950,875
1,540,841
10,491,716
8,820,006
1,552,251
10,372,257
9,585,089
1,390,946
10,976,035
Energy sales, kWh (in thousands):
Retail:
Residential ..............................................................................................
Commercial and industrial, small ...........................................................
Commercial and industrial, large............................................................
Sales to public authorities.......................................................................
Total retail .....................................................................................
Wholesale:
Sales for resale........................................................................................
Off-system sales......................................................................................
Total wholesale..............................................................................
Total energy sales...................................................................
Losses and Company use ...............................................................................
Total .......................................................................................
2,823,260
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
Native system:
Peak load, kW ................................................................................................
Net dependable generating capability for peak, kW......................................
1,935,000
2,082,000
Total system:
Peak load, kW (2) ..........................................................................................
Net dependable generating capability for peak, kW......................................
1,982,000
2,082,000
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
1,892,000
2,080,000
2,027,000
2,080,000
2,771,138
2,384,514
1,062,662
1,585,568
7,803,882
63,347
2,500,947
2,564,294
10,368,176
607,859
10,976,035
1,794,000
2,055,000
1,992,000
2,055,000
___________________________
(1)
(2)
The number of retail customers presented is based on the number of service locations.
Includes spot sales and net losses of 47,000 kW, 135,000 kW and 198,000 kW for 2017, 2016 and 2015, 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) transactions,
transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and
the FERC are subject to judicial review.
Texas Regulatory Matters
2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities
incorporated in its Texas service territory, and the PUCT in Docket No. 44941, a request for an annual increase in non-fuel base
revenues ("2015 Texas Retail Rate Case").
On July 21, 2016, the parties to PUCT Docket No. 44941 filed the Joint Motion to Implement Uncontested Amended and
Restated Stipulation and Agreement which was unopposed by the parties (the "2016 Unopposed Settlement"). On August 25, 2016,
the PUCT approved the 2016 Unopposed Settlement and issued its final order in Docket No. 44941 ("2016 PUCT Final Order"),
as proposed. The 2016 PUCT Final Order provided for: (i) an annual non-fuel base rate increase, lower annual depreciation expense,
a revised return on equity for allowance for funds used during construction ("AFUDC") purposes, and the inclusion of substantially
all new plant in service in rate base; (ii) an additional annual non-fuel base rate increase of $3.7 million related to Four Corners
costs, which was collected through a surcharge that terminated on July 11, 2017; (iii) removing the separate rate treatment for
residential customers with solar systems that the Company had proposed in its August 10, 2015 filing; (iv) allowing the Company
to recover $3.1 million in rate case expenses through a separate surcharge; and (v) allowing the Company to recover revenues
associated with the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 through a separate
surcharge.
Interim rates associated with the annual non-fuel base rate increase became effective on April 1, 2016. The additional
surcharges associated with the incremental Four Corners costs, rate case expenses and the relate back of rates to consumption on
and after January 12, 2016 through March 31, 2016 were implemented on October 1, 2016.
For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail
Rate Case until it received the 2016 PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016
the cumulative effect of the 2016 PUCT Final Order, which related back to January 12, 2016.
2017 Texas Retail Rate Case Filing. On February 13, 2017, the Company filed with the City of El Paso, other municipalities
incorporated in the Company's Texas service territory and the PUCT in Docket No. 46831, a request for an increase in non-fuel
base revenues ("2017 Texas Retail Rate Case"). On November 2, 2017, the Company filed the Joint Motion to Implement
Uncontested Stipulation and Agreement with the Administrative Law Judges for the 2017 Texas Retail Rate Case.
On December 18, 2017, the PUCT issued its final order in the Company's rate case pending in Docket No. 46831 ("2017
PUCT Final Order"), which provides, among other things, for the following: (i) an annual non-fuel base rate increase of $14.5
million; (ii) a return on equity of 9.65%; (iii) all new plant in service as filed in the Company's rate filing package was prudent
and used and useful and therefore is included in rate base; (iv) recovery of the costs of decommissioning Four Corners in the
amount of $5.5 million over a seven year period beginning August 1, 2017; (v) the Company to recover reasonable rate case
expenses of approximately $3.4 million through a separate surcharge over a three year period; and (vi) a requirement that the
Company file a refund tariff if the federal statutory income tax rate, as it relates to the Company, is decreased before the Company
files its next rate case. The 2017 PUCT Final Order also establishes baseline revenue requirements for recovery of future transmission
and distribution investment costs, and includes a minimum monthly bill of $30.00 for new residential customers with distributed
generation, such as private rooftop solar. Additionally, the 2017 PUCT Final Order allows for the annual recovery of $2.1 million
of nuclear decommissioning funding and establishes annual depreciation expense that is approximately $1.9 million lower than
the annual amount requested by the Company in its initial filing. Finally, the 2017 PUCT Final Order allows for the Company to
recover revenues associated with the relate back of rates to consumption on and after July 18, 2017 through a separate surcharge.
New base rates, including additional surcharges associated with rate case expenses and the relate back of rates to consumption
on and after July 18, 2017 through December 31, 2017 were implemented in January 2018.
For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2017 Texas Retail
Rate Case until it received the 2017 PUCT Final Order on December 18, 2017. Accordingly, it reported in the fourth quarter of
2017 the cumulative effect of the 2017 PUCT Final Order, which related back to July 18, 2017.
12
The 2017 PUCT Final Order requires the Company to file a refund tariff if the federal statutory income tax rate, as it relates
to the Company, is decreased before the Company files its next rate case. Following the enactment of the Tax Cuts and Jobs Act
of 2017 ("TCJA") on December 22, 2017, and in compliance with the 2017 PUCT Final Order, the Company will reduce the
recognition of Texas jurisdictional revenues beginning January 1, 2018, to approximate the tax savings resulting from the TCJA
and will file a refund tariff which the Company will ask to be implemented in the first half of 2018. The refund tariff is expected
to be reflected in rates over a period of a year and will be updated annually until new base rates are implemented pursuant to the
Company's next rate case filing. See Part II, Item 8, Financial Statements and Supplementary Data, Note J for further details.
Energy Efficiency Cost Recovery Factor. On May 1, 2017, the Company filed its annual application, which was assigned
PUCT Docket No. 47125, to establish its energy efficiency cost recovery factor ("EECRF") for 2018. In addition to projected
energy efficiency costs for 2018 and a true-up to prior year actual costs, the Company requested approval of an incentive bonus
for the 2016 energy efficiency program results in accordance with PUCT rules. Interim rates were approved effective January 1,
2018. The Company, the staff of the PUCT, and the City of El Paso reached an agreement that includes an incentive bonus of $0.8
million. The agreement was filed on January 25, 2018, and was approved by the PUCT on February 15, 2018.
Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered
from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows
the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon
the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires
the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount
and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to
surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery
to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the
previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT
in fuel reconciliation proceedings.
On November 30, 2016, the Company filed a request, which was assigned PUCT Docket No. 46610, to increase its fixed
fuel factor by approximately 28.8% to reflect increased fuel expenses primarily related to an increase in the price of natural gas
used to generate power. The increase in the fixed fuel factor was effective on an interim basis January 1, 2017 and approved by
the PUCT on January 10, 2017. As of September 30, 2017, the Company had over-recovered fuel costs in the amount of $1.1
million for the Texas jurisdiction. On October 13, 2017, the Company filed a request, which was assigned PUCT Docket No.
47692, to decrease the Texas fixed fuel factor by approximately 19% to reflect decreased fuel expenses primarily related to a
decrease in the price of natural gas used to generate power. The decrease in the Texas fixed fuel factor became effective beginning
with the November 2017 billing month and will continue thereafter until changed by the PUCT. At December 31, 2017, the
Company had a net fuel over-recovery balance of approximately $5.8 million in Texas.
Fuel Reconciliation Proceeding. On September 27, 2016, the Company filed an application with the PUCT, designated as
PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of
April 1, 2013 through March 31, 2016. On June 29, 2017, the PUCT approved a settlement in this proceeding. The settlement
provides for the reconciliation of fuel and purchased power costs incurred from April 1, 2013 through March 31, 2016. Additionally,
the settlement modifies and tightens the Palo Verde performance rewards measurement bands beginning with the 2018 performance
period. The financial results for the twelve months ended December 31, 2017 include a $5.0 million, pre-tax increase to income
reflecting the settlement of the Texas fuel reconciliation proceeding. This amount represents Palo Verde performance rewards
associated with the 2013 to 2015 performance periods net of disallowed fuel and purchased power costs as approved in the
settlement. Texas jurisdictional fuel and purchased power costs subject to prudence review are costs from April 1, 2016 through
December 31, 2017 that total approximately $250.9 million.
Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program that
includes the construction and ownership of a 3 MW solar photovoltaic system located at the Company's MPS. Participation is on
a voluntary basis, and customers contract for a set capacity (kW) amount and receive all energy produced. This case was assigned
PUCT Docket No. 44800. The Company filed a settlement agreement among all parties on July 1, 2016 approving the program,
and the PUCT approved the settlement agreement and program on September 1, 2016. On April 19, 2017, the Company announced
that the entire 3 MW program was fully subscribed by approximately 1,500 Texas customers. The Community Solar facility began
commercial operation on May 31, 2017.
Four Corners Generating Station. On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement
providing for the sale of the Company's interest in Four Corners to APS. The sale of the Company's interest in Four Corners closed
on July 6, 2016. See Part II, Item 8, "Financial Statements and Supplementary Data, Note E of Notes to Financial Statements" for
further details on the sale of Four Corners.
13
On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and
certain rate and accounting findings related to the Purchase and Sale Agreement. This case was assigned PUCT Docket No. 44805.
Subsequent to the filing of the application, the case was subject to numerous procedural matters, including a March 23, 2016 order
in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the
requested rate and accounting findings, including coal mine reclamation costs, in a rate case proceeding. On September 1, 2016,
a motion by parties in the proceeding to suspend the procedural schedule in order to pursue settlement was approved. On March 3,
2017, the Company filed a Joint Motion to Implement Stipulation and Agreement (the "Stipulation and Agreement"), and PUCT
Staff filed its recommendation that the Company’s disposition of its interest in Four Corners was reasonable and consistent with
the public interest. Additionally, the signatories of the Stipulation and Agreement agreed to support the recovery of the Company's
Four Corners decommissioning costs in the 2017 Texas Retail Rate Case. A final order approving the Stipulation and Agreement
was adopted by the PUCT on March 30, 2017. The approval to recover Four Corners decommissioning costs was included in the
2017 PUCT Final Order.
Other Required Approvals. The Company has obtained other required approvals for tariffs and other approvals required by
the Texas Public Utility Regulatory Act ("PURA") and the PUCT.
New Mexico Regulatory Matters
2015 New Mexico Rate Case Filing. On May 11, 2015, the Company filed a request with the NMPRC, in Case No. 15-00127-
UT, for an annual increase in non-fuel base rates. On June 8, 2016, the NMPRC issued its final order in Case No. 15-00127-UT
(the "NMPRC Final Order") which approved an annual increase in non-fuel base rates of approximately $0.6 million, an increase
of approximately $0.5 million in other service fees and a decrease in the Company's allowed return on equity to 9.48%. The
NMPRC Final Order concluded that all of the Company's new plant in service was reasonable and necessary and therefore would
be recoverable in rates. The Company's rates were approved by the NMPRC effective July 1, 2016 and implemented at such time.
Future New Mexico Rate Case Filing. NMPRC Case No. 15-00109-UT required the Company to make a rate filing in
New Mexico in the second quarter of 2017 using a historical test year ended December 31, 2016. On March 24, 2017, the Company,
NMPRC Utility Division Staff and the New Mexico Attorney General filed a Joint Motion to Modify Filing Date Stated in Final
Order requesting that the rate filing date be changed to no later than July 31, 2019, using the appropriate historical test year period.
The joint request was approved by the NMPRC on April 12, 2017. The NMPRC has initiated an investigation into the impact of
the TCJA on utility customers that may require earlier action by the Company. The Company is evaluating possible approaches
to begin providing a refund credit for the TCJA income tax rate decrease to New Mexico customers.
Fuel and Purchased Power Costs. Historically, fuel and purchased power costs were recovered through base rates and a Fuel
and Purchased Power Cost Adjustment Clause (the "FPPCAC") that accounts for changes in the costs of fuel relative to the amount
included in base rates. Effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power
costs are no longer recovered through base rates but are recovered through the FPPCAC. The Company's request to reconcile its
fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in Case No. 15-00127-
UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2017 that
total approximately $173.1 million. At December 31, 2017, the Company had a net fuel over-recovery balance of approximately
$0.4 million in New Mexico. As required, the Company filed a request to continue use of its FPPCAC with the NMPRC on January
5, 2018 which was assigned NMPRC Case No. 18-00006-UT.
5 MW HAFB Facility Certificate of Convenience and Necessity ("CCN"). On October 7, 2015, in NMPRC Case No. 15-00185-
UT, the NMPRC issued a final order approving a CCN for a 5 MW solar power generation facility located on HAFB in the
Company's service territory in New Mexico. The Company and HAFB negotiated a retail contract, which includes a power sales
agreement for the facility, to replace the existing load retention agreement which was approved by final order issued October 5,
2016 in NMPRC Case No. 16-00224-UT. Construction of the solar generation facility is expected to be completed in the third
quarter of 2018.
New Mexico Efficient Use of Energy Recovery Factor. On July 1, 2016, the Company filed its annual application requesting
approval of its 2017 Energy Efficiency and Load Management Plan and to establish energy efficiency cost recovery factors for
2017. In addition to projected energy efficiency costs for 2017, the Company requested approval of a $0.4 million incentive for
2017 energy efficiency programs in accordance with NMPRC rules. This case was assigned Case No. 16-00185-UT. On
February 22, 2017, the NMPRC issued a Final Order approving the Company’s 2017 Energy Efficiency and Load Management
Plan and authorizing recovery in 2017 of a base incentive of $0.4 million. The Company’s energy efficiency cost recovery factors
were approved and effective in customer bills beginning on March 1, 2017.
On July 1, 2016, the Company filed its 2015 Annual Report for Energy Efficiency Programs, which included an incentive
for verified 2015 program performance of $0.3 million, which was approved in Case No. 13-00176-UT. The Company recorded
14
the $0.3 million approved incentive in operating revenues in the first quarter of 2017. In addition, on June 30, 2017, the Company
filed its 2016 Annual Report for Energy Efficiency Programs, which included an incentive for verified 2016 program performance
of $0.4 million that was approved in Case No. 13-00176-UT. The Company recorded the $0.4 million approved incentive in
operating revenues in the third quarter of 2017.
Revolving Credit Facility, Issuance of Long-Term Debt, and Securities Financing. On October 7, 2015, the Company received
approval in NMPRC Case No. 15-00280-UT to guarantee the issuance of up to $65.0 million of long-term debt by the Rio Grande
Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations, which
remains effective. On October 4, 2017, the Company received additional approval in NMPRC Case No. 17-00217-UT to amend
and extend its Revolving Credit Facility ("RCF"), issue up to $350.0 million in long-term debt and to redeem and refinance the
$63.5 million 2009 Series A 7.25% Pollution Control Bonds and the $37.1 million 2009 Series B 7.25% Pollution Control Bonds,
which have optional redemptions beginning in 2019. The NMPRC approval to issue $350.0 million in long-term debt supersedes
its prior approval.
Other Required Approvals. The Company has obtained other required approvals for tariffs and other approvals as required
by the New Mexico Public Utility Act and the NMPRC.
Federal Regulatory Matters
Revolving Credit Facility; Issuance of Long-Term Debt, Securities Financing, and Guarantee of Debt. On October 31, 2017,
the FERC issued an order in Docket No. ES17-54-000 approving the Company’s filing to (i) amend and extend the RCF; (ii) issue
up to $350.0 million in long-term debt; (iii) guarantee the issuance of up to $65.0 million of long-term debt by the RGRT; and (iv)
redeem and refinance the $63.5 million 2009 Series A 7.25% Pollution Control Bonds and the $37.1 million 2009 Series B 7.25%
Pollution Control Bonds, which have optional redemptions beginning in 2019. The order also approves the Company's request to
continue to utilize the Company's existing RCF with the ability to amend and extend at a future date. The authorization is effective
from November 15, 2017 through November 14, 2019 and supersedes prior FERC approvals.
Other Required Approvals. The Company has obtained required approvals for rates, tariffs and other approvals as required
by the FERC.
United States Department of Energy. The DOE regulates the Company's exports of power to Mexico pursuant to a DOE
grant of export authorization. In addition, the Company is the holder of two presidential permits issued by the DOE under which
the Company constructed and operates border facilities crossing the United States/Mexico border.
The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's
uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See "Facilities – Palo Verde" for discussion
of spent fuel storage and disposal costs.
Sales for Resale and Network Transmission Service to Rio Grande Electric Cooperative
The Company provides firm capacity and associated energy to the Rio Grande Electric Cooperative ("RGEC") pursuant to
an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission
service to the RGEC pursuant to the Company's Open Access Transmission Tariff ("OATT"). The contract includes a formula-
based rate that is updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible
fuel and purchased power costs allocable to the RGEC. The Company's service to RGEC is regulated by FERC.
Power Sales Contracts
The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2017.
15
Franchises and Significant Customers
Franchises
The Company operates under franchise agreements with several cities in its service territory, including one with El Paso,
Texas, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve
its customers within El Paso. Pursuant to the El Paso franchise agreement, which was amended in 2010, the Company pays to the
City of El Paso, on a quarterly basis, a fee equal to 4.00% of gross revenues the Company receives for the generation, transmission
and distribution of electrical energy and other services within the city. The 2005 El Paso franchise agreement set the franchise fee
at 3.25% of gross revenues, but the 2010 amendment added an incremental fee equal to 0.75% of gross revenues to be placed in
a restricted fund to be used by the city solely for economic development and renewable energy purposes. Any assignment of the
franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of
the City of El Paso. The El Paso franchise agreement is set to expire on July 31, 2030.
The Company does not have a written franchise agreement with Las Cruces, New Mexico, the second largest city in its
service territory. The Company utilizes public rights-of-way necessary to service its customers within Las Cruces under an implied
franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009. The Company pays the City
of Las Cruces a franchise fee of 2.00% of gross revenues the Company receives from services within the City of Las Cruces.
Military Installations
The Company serves HAFB, White Sands and Fort Bliss. These military installations represent approximately 2.5% of the
Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss under which Fort Bliss takes
retail electric service from the Company under the applicable Texas tariffs. The Company serves White Sands under the applicable
New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under which the Company provides retail electric
service and limited wheeling services to HAFB under the applicable New Mexico tariffs. As stated in the contract, HAFB will
purchase the full output of a Company-owned 5 MW solar facility upon its completed construction, with HAFB's other power
requirements and limited wheeling services provided under the applicable New Mexico tariffs.
Other Information
Investors should note that we announce material financial information in our filings with the SEC, press releases and public
conference calls. Based on guidance from the SEC, we may also use the Investor Relations section of our website
(www.epelectric.com) to communicate with investors about the Company. It is possible that the financial information we post
there could be deemed to be material information. The information contained on or accessible from our website is not incorporated
by reference into and does not constitute a part of this Annual Report on Form 10-K.
16
Item 1A.
Risk Factors
Like other companies in our industry, our financial results are impacted by weather, the economy of our service territory,
market prices for power, fuel prices, and the decisions of regulatory agencies. Our common stock price and creditworthiness will
be affected by local, regional and national macroeconomic trends, general market conditions and the expectations of the investment
community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect
our financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the
statements below must be read together with factors discussed elsewhere in this Annual Report on Form 10-K and in our other
filings with the SEC.
Our Revenues and Profitability Depend Upon Regulated Rates
Our retail rates are subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. The
2017 PUCT Final Order established our current retail base rates in Texas, effective July 18, 2017. In addition, the NMPRC Final
Order established rates in New Mexico that became effective in July 2016.
Our profitability depends on our ability to recover the costs, including a reasonable return on invested capital, of providing
electric service to our customers through base rates approved by our regulators. These rates are generally established based on an
analysis of the expenses we incur in a historical test year, and as a result, the rates ultimately approved by our regulators may or
may not match our expenses at any given time and recovery of expenses may lag behind the occurrence of those expenses. Rates
in New Mexico may be established using projected costs and investment for a future test year period in certain instances. While
rate regulation is based on the assumption that we will have a reasonable opportunity to recover our costs and earn a reasonable
rate of return on our invested capital, there can be no assurance that our future Texas rate cases or New Mexico rate cases will
result in base rates that will allow us to fully recover our costs including a reasonable return on invested capital. There can be no
assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including costs
associated with future plant retirements. It is also likely that third parties will intervene in any rate cases and challenge whether
our costs are reasonable and necessary. If all of our costs are not recovered, or timely recovered, through the retail base rates
ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely
affect our ability to meet our financial obligations.
We May Not Be Able To Recover All Costs of New Generation and Transmission Assets
We received approval, both from the PUCT and the NMPRC, to construct Units 3 and 4, two 89 MW simple-cycle
aeroderivative combustion turbines at MPS. In 2016, we completed construction of these units, which began commercial operation
in May 2016 and September 2016, respectively. The PUCT approved the inclusion of the Texas jurisdictional portion of MPS
Units 3 and 4 in base rates in the 2017 PUCT Final Order. However, the New Mexico jurisdiction portion of MPS Units 3 and 4
have not yet been approved by the NMPRC for inclusion in customer base rates. Accordingly, we are exposed to the risk of failing
to recover these costs as well as costs associated with the construction of other new units and transmission and distribution assets.
In addition, if future units are not completed on time, we may be required to purchase power or operate less efficient generating
units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the
PUCT and the NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting
from delays in the completion of these new units or other new units.
Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital
Programs and Increase Our Funding Obligations for Pensions and Decommissioning
The global credit and equity markets and the overall economy can be extremely volatile which could have a number of
adverse effects on our operations and capital programs. For example, tight credit and capital markets could make it difficult and
more expensive to raise capital to fund our operations and capital programs. If we are unable to access the credit markets, we could
be required to defer or eliminate important capital projects in the future. In addition, declines in the stock market performance
may reduce the value of our financial assets and decommissioning trust investments. Similarly, inflationary increases will increase
our future decommission obligations. Such market results may also increase our funding obligations for our pension plans, other
post-retirement benefit plans and nuclear decommissioning trusts. Changes in the corporate interest rates that we use as the discount
rate to determine our pension and other post-retirement liabilities may have an impact on our funding obligations for such plans
and trusts. Further, continued economic volatility may result in reduced customer demand, both in the retail and wholesale markets,
and increases in customer delinquencies and write-offs. Uncertainty in the credit markets may negatively impact the ability of our
customers to finance purchases of our services and could adversely affect the collectability of our receivables. Similarly, actions
or inaction of Congress and of governmental agencies can impact our operations. For example, during 2013, sales to public
authorities and small commercial and industrial customers were negatively impacted by the federal government sequestration and
17
shutdown. The credit markets and overall economy (including inflationary increases) may also adversely impact our ability to
arrange future financings on acceptable terms and therefore our ability to refinance our existing indebtedness could be limited.
Furthermore, the credit markets and overall economy may also adversely impact the financial health of our suppliers. If that were
to occur, our access to and prices for inventory, supplies and capital equipment could be adversely affected. Our power trading
counterparties could also be adversely impacted by the market and economic conditions which could result in reduced wholesale
power sales or increased counterparty credit risk. Declines in revenues, earnings and cash flow from these events could impact
our ability to fund construction expenditures and impact the level of dividend payments.
There are Inherent Risks in the Ownership of Nuclear Facilities
Our 15.8% ownership interest in Palo Verde, which is the largest nuclear electric generating facility in the United States,
subjects us to a number of risks. A significant percentage of our generating capacity, off-system sales margins, assets and operating
expenses is attributable to Palo Verde. Our interest in each of the three Palo Verde units totals approximately 633 MW of generating
capacity. Palo Verde represents approximately 30% of our available net generating capacity and provided approximately 49% of
our energy requirements for the twelve months ended December 31, 2017. Palo Verde comprises approximately 25% of our total
net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the
operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and
costs at Palo Verde. Palo Verde operated at a capacity factor of 93.8% and 93.2% in the twelve months ended December 31, 2017
and 2016, respectively.
We participate in Palo Verde with one or more parties who may not have the same goals, strategies, priorities or resources
as we do and may compete with us. Furthermore, regulatory compliance issues and financial restraints could cause these parties
to make decisions that could potentially be adverse to us.
As Palo Verde is a nuclear electric generating facility, it is subject to environmental, health and financial risks, such as the
ability to obtain adequate supplies of nuclear fuel and water; the ability to dispose of spent nuclear fuel; increases in decommissioning
costs due to inflation and regulatory changes, the ability to maintain adequate trust fund reserves for decommissioning; potential
liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; cyber
attacks, or other causes; and unscheduled outages due to equipment and other problems. If a nuclear incident were to occur at Palo
Verde, it could materially and adversely affect our results of operations and financial condition. A major incident at a nuclear
facility anywhere in the world could cause regulatory bodies to limit or prohibit the operation or licensing of any domestic nuclear
unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.
We May Not Be Able to Recover All of Our Fuel Expenses from Customers On a Timely Basis Or at All
In general, by law, we are entitled to recover our reasonable and necessary fuel and purchased power expenses from our
customers in Texas and New Mexico. NMPRC Case No. 13-00380-UT provides for energy delivered to New Mexico customers
from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon a previous purchased
power contract. Fuel and purchased power expenses in Texas and New Mexico are subject to reconciliation by the PUCT and
NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs such that fuel revenues equal
recoverable fuel and purchased power expense including the re-priced energy costs for Palo Verde Unit 3 in New Mexico. In the
event that recovery of fuel and purchased power expenses is denied in any reconciliation proceeding, the amounts recorded for
fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would
incur a loss to the extent of the disallowance.
In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust
for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. In
Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision
except in the month of December. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any
time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods
of significant increases in natural gas prices, we realize a lag in the ability to reflect increases in fuel costs in our fuel recovery
mechanisms in Texas. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from
customers. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely
recovery of such costs, we could experience a material negative impact on our cash flow.
Weather Conditions Affect the Demand for Electricity or Could Result in Unplanned Outages
Our service territory is in west Texas and southern New Mexico and is particularly susceptible to dry and hot temperatures
in the summer months. These seasonal weather patterns result in temperatures that can lead to daytime highs exceeding 100 degrees
Fahrenheit for extended periods during the summer when we typically experience peak kWh sales at higher summer rates. Milder
18
temperatures during this period will occur occasionally and result in less kWh sales which will adversely affect our results of
operations. From time to time, we experience extreme weather conditions, including high winds (usually in the spring months but
can occur during other months), that may result in unplanned outages. Under such conditions, we may incur additional costs to
repair and, or, to replace equipment. Depending upon the length and extent of the damage, we may also incur additional purchase
power costs. Fallen power lines and poles can cause severe damage to customer property and subject us to claims, all of which
could have a material adverse effect on our results of operations and cash flows.
Equipment Failures and Other External Factors Can Adversely Affect Our Results
The generation and transmission of electricity require the use of expensive and complex equipment. While we have a
maintenance program in place, generating plants are subject to unplanned outages because of equipment failure and severe weather
conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these
units. In the event of unplanned outages, we must acquire power from other sources at unpredictable costs in order to supply our
customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and
approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and
purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to
the extent of the disallowance. Unplanned outages could also prevent us from selling excess power at wholesale. In addition,
actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us
to unexpected expenses or to the cost and uncertainty of public policy initiatives. We may also incur additional capital and operating
costs in connection with the physical security and cyber security of transmission lines and generation facilities. Damage to certain
transmission and generation facilities due to vandalism or other deliberate acts, or damage due to severe weather could lead to
outages or other adverse effects. We are particularly vulnerable to this because a significant portion of our available energy (at
Palo Verde) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance
transmission lines. In addition, Palo Verde’s availability is an important factor in realizing off-system sales margins. These factors,
as well as interest rates, economic conditions, fuel prices and price volatility could have a material adverse effect on our earnings,
cash flow and financial position. While we believe that we maintain adequate insurance coverage for such incidents, there is no
assurance that all costs in excess of deductible amounts will be reimbursed or that we can maintain such coverage limits in the
future at competitive market rates. In the event future insurance costs and/or deductible amounts increase, our financial condition,
operating results and cash flows could be materially adversely affected.
Competition and Deregulation Could Result in a Loss of Customers and Increased Costs
As a result of changes in federal law, our wholesale and large retail customers have access to, in varying degrees, alternative
sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate
our transmission and distribution functions, which would remain regulated, from our power generation and energy services
businesses, which would operate in a competitive market, in the future. In 2004, the PUCT approved a rule delaying retail
competition in our Texas service territory. This rule was codified in the PURA in June 2011. The PURA identifies various milestones
that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and
commencement of independent operation of a regional transmission organization in the area that includes our service territory.
This and other milestones are not likely to be achieved for a number of years, if at all. There is substantial uncertainty about both
the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas
service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable.
There can be no assurance that deregulation would not adversely affect our future operations, cash flow and financial condition.
Future Costs of Compliance with Environmental Laws and Regulations Could
Adversely Affect Our Operations and Financial Results
We are subject to extensive federal, state and local environmental laws and regulations relating to discharges into the air,
air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and
non-hazardous substances and wastes, natural resources, and health and safety. Compliance with these legal requirements, which
change frequently and often become more restrictive, could require us to commit significant capital and operating resources toward
permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchases of
air emission allowances and/or offsets. These laws and regulations could also result in limitations in operating hours and/or changes
in construction schedules for future generating units.
Cost of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not
recovered in our rates, could adversely affect our operations and financial results, especially if emission and/or discharge limits
are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and
types of assets we operate increase. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or
19
the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of
implementation of environmental laws or regulations. For example, the EPA has issued in the recent past various proposed
regulations regarding air emissions, such as the revision of the primary and secondary ground-level ozone NAAQS. If these
regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our
financial results.
Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for
Electricity or Availability of Resources, and Could Result in Increased Compliance Costs
We emit GHG (including carbon dioxide) through the operation of our power plants. Federal legislation had been introduced
in both houses of Congress to regulate GHG emissions and numerous states have adopted programs to stabilize or reduce GHG
emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA.
In October 2015, the EPA published a rule establishing guidelines for states to regulate CO2 emissions from existing power
plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. We cannot at this time determine the
impact of the CPP, related proposals and legal challenges may have on our financial condition, results of operations or cash flows.
Further, in April 2016, the U.S. signed the 21st Conference of Parties Paris Agreement, which requires countries to set and "represent
a progression" in GHG emission reduction goals every five years beginning in 2020. In August 2017, the United States formally
documented to the United Nations its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date
from the Paris Agreement is November 2020. The potential impact of this agreement and GHG rules (if and when finalized) on
us is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or changes in construction
schedules for future generating units.
It is not possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi-state
regions or any GHG regulations adopted by the EPA or state environmental agencies will impact our business. However, any
legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional
operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit GHG, and could
have a material adverse effect on our business, financial condition, reputation or results of operations.
Adverse Regulatory Decisions or Changes in Applicable Regulations Could Have a Material Adverse Effect on Our
Business or Result in Significant Additional Costs
Our business is subject to extensive federal, state and local laws and regulations regarding safety and performance, siting
and construction of facilities, customer service and the rates we can charge our customers, among other things. FERC regulates
our wholesale operations, provision of transmission services and compliance with federally mandated reliability standards. FERC
has issued a number of rules pertaining to preventing undue discrimination in transmission services and electric reliability standards.
Under the Energy Policy Act of 2005, FERC can impose penalties (up to $1,238,271 per violation, per day) for failure to comply
with statutes, rules and orders within FERC's jurisdiction, including mandatory electric reliability standards. Additional regulatory
authorities have jurisdiction over some of our operations and construction projects, including the EPA, the DOE, the PUCT, the
NMPRC and various local regulatory districts (including the cities of El Paso and Las Cruces).
We must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective
orders. Should we be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any
investigations or enforcement actions or impose penalties or disallowances on us, our business could be adversely affected. Existing
regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to us or our
facilities in a manner that may have a detrimental effect on our business or result in significant additional costs because of our
obligation to comply with those requirements.
Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our Infrastructure Could
Interfere With Our Operations, Could Expose Us or Our Customers or Employees to a Risk of Loss, and Could Expose
Us to Liability, Regulatory Penalties, Reputational Damage and Other Harm to Our Business
We rely upon our infrastructure to manage or support a variety of business processes and activities, including the generation,
transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers.
We also use information technology systems for internal accounting purposes and to comply with financial reporting, legal and
tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns
due to attacks by hackers, breaches due to employee error or malfeasance, system failures, computer viruses, natural disasters, a
physical attack on our facilities, or other catastrophic events. The occurrence of any of these events could impact the reliability of
our generation, transmission and distribution systems and energy marketing and trading functions; could expose us or our customers
or employees to a risk of loss or misuse of confidential information; and could result in legal claims or proceedings, liability or
20
regulatory penalties against us, damage our reputation or otherwise harm our business. In addition, we may be required to incur
significant costs to prevent or respond to damage caused by these disruptions or security breaches in the future.
Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy
industry in general. The effects of such attacks against us or others in the energy industry could increase the cost of regulatory
compliance, increase the cost of insurance coverage or result in a decline in the U.S. economy which could negatively affect our
results of operations and financial condition. Ongoing and future governmental efforts to regulate cybersecurity in the energy
industry could lead to increased regulatory compliance costs.
The Effects of Technological Advancement, Energy Conservation Measures and Distributed Generation Could
Adversely Affect Our Operations and Financial Results
New technologies may emerge that could be superior to, or may not be compatible with, some of our existing technologies,
and may require us to make significant expenditures to remain competitive. Our future success will depend, in part, on our ability
to anticipate and adapt to technological changes in a cost-effective manner and to offer, on a timely basis, services that meet
customer demands and evolving industry standards.
Additionally, the electric utility industry is undergoing other technological advances such as the expanded cost effective
utilization of energy efficiency measures, energy storage, and distributed generation including solar rooftop projects. Customers’
increased use of energy efficiency measures, energy storage, and distributed generation could result in lower demand. Reduced
demand due to energy efficiency measures, energy storage, and the use of distributed generation, to the extent not substantially
offset through ratemaking mechanisms, could have a material adverse impact on our financial condition, results of operations and
cash flows.
Inflation Could Adversely Affect Our Financial Results
For the past several years, inflation has been relatively low and, therefore has had little impact on our results of operations
and financial condition. However, should we experience increases in costs due to inflationary impacts, any delays in requesting
and receiving compensatory increases in our base rates could have a material adverse impact on our financial condition, results
of operations and cash flows.
Our Line of Business Is Concentrated Solely to the Electric Industry and to One Region
We are a fully vertically integrated electric utility company whose only business is the generation, transmission and distribution
of electricity to customers in an area of approximately 10,000 square miles in west Texas and southern New Mexico. Approximately
90% of revenues are directly related to the retail sales of electric power to approximately 417,900 residential, commercial and
public authority customers. As such, risks uniquely associated with the utility industry such as changes in utility legislation and
regulations, weather patterns in the region and economic conditions will have a greater effect on our overall operating results than
otherwise if our operations were more diversified into other lines of business and in a broader geographical area.
New Laws, Regulations and Policies Announced by the Trump Administration Could Impact Our Operations
President Donald Trump campaigned on a number of issues, including increasing border security and immigration regulations,
overhauling federal taxes, repealing the Patient Protection Affordable Care Act, withdrawal from the Trans Pacific Partnership
agreement, enacting duties on NAFTA imports and reducing the burdens of environmental and climate change regulations. Since
President Trump’s inauguration, he has initiated executive orders towards achieving some of these goals; however it is uncertain
to what extent President Trump proposes additional new executive orders and the effect such orders will have on the national,
regional and local economies. Our service territory borders with Mexico and as such businesses in our service territory rely heavily
on commerce with businesses in Mexico. Changes in regulations restricting such commerce activities could reduce our customer
growth rate and materially adversely affect our results of operations, financial condition and cash flows.
On December 22, 2017, the TCJA was signed into law, enacting significant changes to the Internal Revenue Code ("IRC”).
Key provisions impacting the Company include a reduction in the corporate income tax rate from 35% to 21% effective January
1, 2018, the discontinuation of bonus depreciation for regulated public utilities for assets acquired and placed into service after
September 27, 2017, elimination of corporate alternative minimum tax provisions, limitations on the utilization of net operating
losses ("NOL") arising after December 31, 2017 to 80% of taxable income with no carryback but with an indefinite carryforward,
and additional limitations on the deductibility of executive compensation. We continue to evaluate the impact of the TCJA as
regulations and accounting standards related to the TCJA are finalized to determine whether changes could have a material adverse
effect on our results of operations, financial condition, and cash flows.
21
The Operation of Transmission Lines on Public and Private Properties, including Indian Lands, Could Result in
Uncertainty Related to Continued Easements and Rights-of-way and Significantly Impact Our Business
Portions of our transmission lines are located on public and private properties, including Indian lands, pursuant to easements
or other rights-of-way that are effective for specified periods. We are unable to predict the final outcome of pending or future
approvals by applicable property owners and governing bodies with respect to renewals of these easements and rights-of-way.
Failure to Successfully Operate Our Facilities or Perform Certain Corporate Functions May Adversely Affect Our
Operations and Financial Condition
Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks,
including:
•
•
•
•
•
•
•
operator error or failure of equipment or processes, including failure to follow appropriate safety protocols;
the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and
environmental and property damage;
operating limitations that may be imposed by environmental or other regulatory requirements;
labor disputes;
information technology or financial system failures, including those due to the implementation and integration of new
technology, that impair our information technology infrastructure, reporting systems or disrupt normal business
operations;
information technology failure that affects our ability to access customer information or causes us to lose confidential
or proprietary data that materially and adversely affects our reputation or exposes us to legal claims; and
catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, natural disasters, terrorism,
pandemic health events or other similar occurrences, which may require participation in mutual assistance efforts by
us or other utilities to assist in power restoration efforts.
Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our
facilities or delays in cash collections, any of which could have a material adverse effect on our results of operations, financial
condition and/or cash flows.
Our Success Depends on the Availability of the Services of a Qualified Workforce and Our Ability to Attract and
Retain Qualified Personnel and Senior Management
Our workforce is aging and many employees have retired in the last few years or are or will become eligible to retire within
the next few years. Although we have undertaken efforts to recruit and train new field service personnel, we may be faced with
a shortage of experienced and qualified personnel. Our costs, including costs to replace employees, productivity costs and safety
costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical
knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability
to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our
results of operations could be negatively affected.
A substantial number of our employees are covered by a collective bargaining agreement that is scheduled to expire in
September 2019. Labor disruptions could occur depending on the outcome of negotiations to renew the terms of this agreement
with the union or if a tentative new agreement is not ratified by its members. In addition, some of our non-represented employees
could join this union in the future. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to
union activities, employee turnover or otherwise, could have a material adverse effect on our business, results of operations and/
or cash flows.
We depend on our senior management and other key personnel. Our success depends on our ability to attract and retain key
personnel. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may
adversely affect our operations. In addition, because of the reliance on our management team, our future success depends in part
on our ability to identify and develop talent to succeed senior management. Any such occurrences could negatively impact our
financial condition and results of operations.
22
Our Ability to Accurately Report Our Financial Results or Prevent Fraud May Be Adversely Affected if We Fail to
Maintain an Effective System of Internal Controls
Effective internal controls are necessary for us to provide reliable financial reports, effectively prevent fraud and operate
successfully as a public company. If our efforts to maintain an effective system of internal controls are not successful, we are
unable to maintain adequate controls over our financial reporting and processes in the future or we are unable to comply with our
obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed, or we may fail to meet
our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial
information, which would likely have a negative effect on the trading price of our common stock and other securities.
Insufficient Insurance Coverage and Increased Insurance Costs Could Adversely Affect Our Operations and
Financial Results
We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we
consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage.
Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance
proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without
negative impact on our results of operations, financial condition and cash flows.
Provisions in Our Corporate Documents, Franchise Agreements and State Law Could Delay or Prevent a Change in
Control of the Company, Even if That Change Would Be Beneficial to Our Shareholders
Our Articles of Incorporation and Bylaws contain provisions that may make acquiring control of the Company difficult and
could preclude our shareholders from receiving a change of control premium, including:
•
•
•
•
•
provisions relating to the classification, nomination and removal of our directors;
provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;
provisions limiting the ability to call special meetings of the shareholders to the Chairman of the Board, our President
and Chief Executive Officer, our Secretary, the majority of the Board of Directors or the holders of at least 25% of the
outstanding shares of our capital stock entitled to vote at such meeting;
provisions restricting our ability to engage in a wide range of “Business Combination” transactions with an “Interested
Shareholder” (generally, any person who owns 15% or more of our outstanding voting power) or any affiliate or associate
of an Interested Shareholder, unless specific conditions are met; and
the authorization given to our Board of Directors or any duly designated committee to issue and set the terms of preferred
stock.
Our El Paso franchise agreement states that any assignment of the franchise agreement, including a deemed assignment as
a result of a change in control of the Company, requires the consent of the City of El Paso. In addition, approval of the NMPRC,
PUCT and FERC would likely be required in any transaction involving a change of control.
In addition, Texas law prohibits us from engaging in a business combination with any shareholder for three years from the
date that person became an affiliated shareholder by beneficially owning 20% or more of our outstanding common stock, in the
absence of certain board of director or shareholder approvals.
23
Item 1B.
Unresolved Staff Comments
None.
Item 2.
Properties
The principal properties of the Company are described in Item 1, "Business," and such descriptions are incorporated herein
by reference. Transmission lines are located either on company-owned land, private rights-of-way, easements or on streets or
highways by public consent.
The Company owns an executive and administrative office building and the Eastside Operations Center (the "EOC") in
El Paso County, Texas. The Company leases land in El Paso, Texas, adjacent to Newman under a lease which expires in June 2033,
subject to a renewal option of 25 years. The Company has several other leases for office and parking facilities that expire within
the next five years.
Item 3.
Legal Proceedings
The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory
commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters,
the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly
analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual
disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the
matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect
on the financial position, results of operations or cash flows of the Company.
See Item 1, "Business – Environmental Matters and Regulation," Item 1, "Regulation," and Part II, Item 8, "Financial
Statements and Supplementary Data, Note C, Note L and Note K of Notes to Financial Statements" for discussion of the effects
of government legislation and regulation on the Company as well as certain pending legal proceedings.
Item 4.
Mine Safety Disclosures
Not Applicable.
24
PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities.
The Company’s common stock trades on the New York Stock Exchange ("NYSE") under the symbol "EE." The intraday
high, intraday low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system
of the NYSE, and quarterly dividends per share paid by the Company for the periods indicated below were as follows:
2016
First Quarter ............... $
Second Quarter ...........
Third Quarter..............
Fourth Quarter ............
2017
First Quarter ............... $
Second Quarter ...........
Third Quarter..............
Fourth Quarter ............
Sales Price
High
Low
Close
Dividends
(End of period)
$
$
46.20
47.27
48.75
48.35
50.75
55.45
56.78
61.15
$
$
37.19
42.42
44.07
42.49
44.70
48.81
50.25
54.60
45.88
47.27
46.77
46.50
50.50
51.70
55.25
55.35
$
$
0.295
0.310
0.310
0.310
0.310
0.335
0.335
0.335
25
Performance Graph
The following graph compares the performance of the Company’s common stock to the performance of Edison Electric
Institute’s ("EEI") index of investor-owned electric utilities and the NYSE Composite, setting the value of each at December 31,
2012 to a base of 100. The table sets forth the relative yearly percentage change in the Company’s cumulative total shareholder
return, assuming reinvestment of dividends, as compared to EEI and the NYSE Composite, as reflected in the graph.
EE
EEI Index
NYSE Composite
As of December 31,
2012
2013
2014
2015
2016
2017
100
100
100
113
113
123
133
146
128
132
140
120
164
164
131
200
184
152
As of January 31, 2018, there were 2,232 holders of record of the Company’s common stock. The Company has been
paying quarterly cash dividends on its common stock since June 30, 2011 and paid a total of $53.3 million in cash dividends
during the twelve months ended December 31, 2017. On February 1, 2018, the Board of Directors declared a quarterly cash
dividend of $0.335 per share payable on March 30, 2018 to shareholders of record as of the close of business on March 16,
2018. Typically, the Board of Directors reviews the Company’s dividend policy annually in the second quarter of each year.
Declaration and payment of dividends is subject to compliance with certain financial tests under Texas law. Since 1999, the
Company has also returned cash to shareholders through a stock repurchase program pursuant to which the Company has
bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s
program, purchases can be made at open market prices or in private transactions and repurchased shares are available for
issuance under employee benefit and stock incentive plans, or may be retired. On March 21, 2011, the Board of Directors
authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock (the "2011 Plan"). No shares
of common stock were repurchased during the twelve months ended December 31, 2017 under the 2011 Plan. The table below
provides the amount of the fourth quarter issuer purchases of equity securities.
26
Period
October 1 to October 31, 2017
November 1 to November 30, 2017
December 1 to December 31, 2017
Total
Number
of Shares
Purchased (a)
Average Price
Paid per Share
(Including
Commissions)
—
—
55.35
— $
—
8,360
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.
For Equity Compensation Plan Information see Part III, Item 12 – "Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters."
Item 6. Selected Financial Data
As of and for the following periods (in thousands except for share and per share data):
Operating revenue.......................................................... $
Operating income...........................................................
Net income ..................................................................... $
Basic earnings per share:
2017
916,797
198,254
98,261
Net income.............................................................. $
2.42
Weighted average number of shares outstanding........... 40,414,556
Diluted earnings per share:
Years Ended December 31,
2016
886,936
194,861
96,768
2.39
$
$
$
$
2015
849,869
146,191
81,918
2.03
2014
917,525
151,163
91,428
2.27
$
$
$
$
2013
890,362
165,635
88,583
2.20
$
$
$
$
$
$
$
$
40,350,688
40,274,986
40,190,991
40,114,594
Net income.............................................................. $
2.42
$
2.39
$
2.03
$
2.27
$
2.20
Weighted average number of shares and dilutive
potential shares outstanding................................... 40,535,191
40,408,033
40,308,562
40,211,717
40,126,647
Dividends declared per share of common stock ............ $
Cash additions to utility property, plant and equipment $
190,305
Total assets (a)................................................................ $ 3,484,363
Long-term debt, net of current portion (a) ..................... $ 1,195,988
Common stock equity .................................................... $ 1,142,165
1.315
$
$
1.225
225,361
$
$
1.165
281,458
$
$
1.105
277,078
$
$
1.045
237,411
$ 3,376,278
$ 3,200,607
$ 3,033,400
$ 2,748,139
$ 1,195,513
$ 1,122,660
$ 1,122,235
$ 1,074,396
$ 1,016,538
$
984,254
$
$
988,436
943,833
________________
(a) The Company implemented Accounting Standards Update ("ASU") 2015-03, Interest- Imputation of Interest (Topic 715)
and ASU 2015-17, Balance Sheet Classification of Deferred Taxes in the first quarter of 2016, retrospectively to all periods
presented in the table above.
27
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
As you read this Management’s Discussion and Analysis of Financial Condition and Results of Operations, please refer to
our Financial Statements and the accompanying notes, which contain our operating results.
Summary of Critical Accounting Policies and Estimates
Our financial statements have been prepared in conformity with U.S. Generally Accepted Accounting Principles ("GAAP").
Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to Financial Statements contains a summary of
our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant
accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex,
subjective assumptions by management, which can materially impact reported results. The Company evaluates its estimates on
an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-
retirement obligations and asset retirement obligations ("ARO"). Changes in these estimates or assumptions, or actual results that
are different, could materially impact our financial condition and results of operation.
Regulatory Accounting
We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC
jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize
them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only
when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders,
regulatory precedent and the current regulatory environment. As of December 31, 2017, we had recorded regulatory assets currently
subject to recovery in future rates of approximately $96.0 million and regulatory liabilities of approximately $296.7 million as
discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Notes D and J of the Notes to Financial
Statements. Regulatory tax assets of approximately $19.6 million related to the regulatory treatment of the equity portion of
AFUDC and approximately $20.9 million related to excess deferred state income taxes are included in regulatory assets. Regulatory
tax liabilities of approximately $289.0 million, primarily related to the reduction of the corporate tax rate from 35% to 21%, are
included in regulatory liabilities and will be refunded to customers.
In the event we determine that we can no longer apply the Financial Accounting Standards Board's (the "FASB") guidance
for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, based on regulatory
action, we could be required to record a charge against income in the amount of the unamortized balance of the related regulatory
assets. Such an action could materially reduce our total assets, specifically our total deferred charges and other assets, and
shareholders' equity.
Collection of Fuel Expense
In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times
of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT
on a periodic basis every one to three years. The NMPRC, in its discretion, may order that a prudence review be conducted to
assure that fuel and purchased power costs recovered from customers are prudently incurred. Prior to the completion of a
reconciliation proceeding or audit, we record fuel transactions such that fuel revenues, including fuel costs recovered through the
FPPCAC in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation
proceeding or an audit, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed
to collect from our customers, and we could incur a loss to the extent of the disallowance.
On September 27, 2016, the Company filed an application with the PUCT, designated as PUCT Docket No. 46308, to
reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March
31, 2016. On June 29, 2017, the PUCT approved a settlement in this proceeding. The settlement provides for the reconciliation
of fuel and purchased power costs incurred from April 1, 2013 through March 31, 2016. As of December 31, 2017, Texas
jurisdictional fuel and purchased power costs subject to prudence review are costs from April 1, 2016 through December 31, 2017
that total approximately $250.9 million. The Company's request to reconcile its fuel and purchased power costs for the period
January 1, 2013 through December 31, 2014 was approved in Case No. 15-00127-UT. New Mexico jurisdictional costs subject
to prudence review are costs from January 1, 2015 through December 31, 2017 that total approximately $173.1 million.
The Company recovers fuel and purchased power costs from the RGEC pursuant to an ongoing contract with a two-year
notice to terminate provision. The contract includes a fuel adjustment clause designed to recover all eligible fuel and purchased
power costs allocable to the RGEC and is updated on an annual basis. This update is reviewed and approved by the RGEC annually
28
in February following the prior calendar year. As of December 31, 2017, the RGEC fuel costs subject to prudence review were
approximately $1.4 million.
Decommissioning Costs and Estimated Asset Retirement Obligation
Pursuant to the ANPP Participation Agreement, the rules and regulations of the Nuclear Regulatory Commission and federal
law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The
determination of the estimated liability is based on site-specific estimates, which are updated every three years and involve numerous
judgments and assumptions, including estimates of future decommissioning costs at current price levels, escalation rates and
discount rates. The Palo Verde ARO is approximately $90.6 million and represents approximately 97% of our total ARO balance
of $93.0 million as of December 31, 2017. A 10% increase in the estimates of future Palo Verde decommissioning costs at current
price levels would have increased the ARO liability by approximately $10.1 million at December 31, 2017. For further details see
Part II, Item 8, "Financial Statements and Supplementary Data, Note E of Notes to Financial Statements."
We are required to fund estimated nuclear decommissioning costs over the life of the generating facilities through the use
of external trust funds pursuant to rules of the NRC, PUCT and the ANPP Participation Agreement. Historically, in Texas and
New Mexico, we have been permitted to collect the funding requirements for our nuclear decommissioning trusts as part of our
rates, except for a portion of Palo Verde Unit 3, which is deregulated in the New Mexico jurisdiction. While we periodically attempt
to seek to recover the costs of decommissioning obligations through our rates, we are not able to conclude, given the currently
available evidence, that it is probable these costs will continue to be collected over the period until decommissioning begins in
2044. We are ultimately responsible for these costs, and our future actions combined with future decisions from regulators will
determine how successful we are in this effort.
The funding amounts are based on assumptions about future investment returns and future decommissioning cost escalations.
If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the nuclear plant increase
beyond our expectations, we would be required to increase our funding to the nuclear decommissioning trusts.
Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We
face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and
which were valued at $130.2 million as of December 31, 2017. A hypothetical 10% increase in interest rates would have reduced
the fair values of these funds by $1.6 million at December 31, 2017. Our decommissioning trust funds also include marketable
equity securities of approximately $149.8 million at December 31, 2017. A hypothetical 20% decrease in equity prices would have
reduced the fair values of these funds by $30.0 million at December 31, 2017. Declines in market prices could require that additional
amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements.
We do not anticipate expending monies held in the nuclear decommissioning trusts before 2044 or a later period when
decommissioning of Palo Verde begins.
Future Pension and Other Post-retirement Obligations
We maintain a qualified noncontributory defined benefit pension plan, which covers substantially all of our employees, and
two non-funded nonqualified supplement plans that provide benefits in excess of amounts permitted under the provisions of the
tax law for certain participants in the qualified plan. We also sponsor a plan that provides other post-retirement benefits, such as
health and life insurance benefits to retired employees. Our net obligations under these various benefit plans at December 31, 2017
totaled $112.4 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled
$2.6 million for the twelve months ended December 31, 2017.
During October 2016, we approved and communicated a plan amendment that resulted in a remeasurement of our other post-
retirement benefit plan. Effective January 1, 2017, retirees and dependents that are less than 65 years of age are offered a choice
between a $1,000 and $2,250 deductible plan. Additionally, retirees and dependents that are 65 years of age or greater are covered
by a fully insured Medicare advantage plan. The impact of these plan changes was a reduction in the other post-retirement benefit
plan obligation of $32.7 million as of December 31, 2016.
Our pension and other post-retirement benefit liabilities and the related net periodic benefit costs are calculated on the basis
of a number of actuarial assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life
expectancy of retirees and health care cost inflation. For 2017, the discount rates used to measure our year end liabilities are based
on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the
timing of the projected future benefit payments. As of December 31, 2017, the corresponding weighted-average discount rates
range from 3.40% to 3.81% depending upon the benefit plan.
29
Our overall expected gross long-term rate of return on assets for the pension trust fund is 7.5% effective January 1, 2018,
which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. Our overall expected gross
long-term rate of return on assets for the other post-retirement benefits trust, on an after-tax basis, is 6.12% effective January 1,
2018. Both expected gross long-term rates of return are based on the after-tax weighted average of the expected returns on
investments. The expected returns on investments in the pension trust and the other post-retirement benefits trust are based upon
the target asset allocations for the two trusts.
Our accrued post-retirement benefit liability and the service and interest components of the related net periodic benefit costs
are calculated using an actuarial assumption regarding health care cost inflation. For measurement purposes, a 6.25%, 7.25%,
4.5% and 10.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018 for pre-65
medical, pre-65 drug, post-65 medical and post-65 drug, respectively. The health care cost trend rates are assumed to decline
steadily to an ultimate rate of 4.5% by 2025 for pre-65 medical and by 2026 for pre-65 and post-65 drug. Post-65 medical trend
is assumed to be 4.5% for all years into the future. Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plan.
The estimated rate of compensation increase used in our retirement plans is 4.5% and is based on recent trends for all non-
union employees and the amounts we are contractually obligated for union employees.
In 2016, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension
and other post-retirement benefits. This change, compared to the previous method, resulted in a decrease in the service cost and
interest cost components of net periodic benefit cost for pension and other post-retirement benefits in 2016 by approximately $2.9
million and $0.8 million, respectively. Historically, we estimated service and interest costs utilizing a single weighted-average
discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. In 2016, we elected
to utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used
in the determination of the benefit obligation to the relevant projected cash flows. We believe the new approach provides a more
precise measurement of service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding
spot rates on the yield curve. We accounted for this change as a change in accounting estimate and accordingly, accounted for this
prospectively.
The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December
31, 2017 reported pension liability and our 2017 reported pension expense (in thousands):
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
$
(48,577)
60,731
$
N/A
N/A
10,044
(9,007)
(3,751)
4,537
(2,742)
2,742
1,318
(1,148)
30
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December
31, 2017 other post-retirement benefit obligations and our 2017 reported other post-retirement benefit expense (in thousands):
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%
Tax Accruals
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
$
(9,582)
12,444
$
(1,212)
1,383
$
11,315
(8,828)
N/A
N/A
2,141
(1,666)
(391)
391
(277)
359
1,117
(848)
N/A
N/A
We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets
and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying
amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we
make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation
or audit adjustments can materially affect amounts we recognize in our financial statements. On December 22, 2017, the TCJA
was enacted. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017.
The TCJA includes significant changes to the IRC, including amendments which significantly change the taxation of business
entities and includes specific provisions related to regulated public utilities. See Note J of the Notes to Financial Statements for
more information.
When appropriate, we record a valuation allowance against deferred tax assets to reflect that these tax assets may not be
realized. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and
character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the
results of operations and financial position of the Company. There were no valuation allowances for deferred tax assets as of
December 31, 2017.
We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount
recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon settlement. The
unrecognized tax benefits that do not meet the recognition and measurement standards were $3.2 million as of December 31, 2017.
The following is an overview of our results of operations for the years ended December 31, 2017, 2016 and 2015. Net income
and basic earnings per share for the years ended December 31, 2017, 2016 and 2015 are shown below:
Overview
Net income (in thousands) .................................................................................... $
Basic earnings per share........................................................................................
$
98,261
2.42
$
96,768
2.39
81,918
2.03
Years Ended December 31,
2017
2016
2015
31
Financial Effect of the PUCT Final Order
On December 18, 2017, the PUCT issued the 2017 PUCT Final Order. See Part II, Item 8, "Financial Statements and
Supplementary Data, Note C of Notes to Financial Statements."
The increase (decrease) on operations resulting from the 2017 PUCT Final Order is categorized in the following periods
based on consumption (in thousands):
Three Months Ended
Twelve
Months
Ended
March
31, 2017
June 30,
2017
September
30, 2017
December
31, 2017
December
31, 2017
Category
Retail non-fuel base rate increase:
$
Relate back............................................
Depreciation and amortization expense.....
Rate case expense ......................................
Pre-tax increase .........................................
Income tax expense ...................................
After-tax increase ...................................... $
$
— $
— $
—
—
— $
—
—
—
— $
—
— $
— $
4,753
(278)
—
4,475
1,566
2,909
$
$
$
4,023
(435)
(58)
3,530
1,236
2,294
$
$
$
8,776
(713)
(58)
8,005
2,802
5,203
32
The following table and accompanying explanations show the primary factors affecting the after-tax change in income
between the calendar years ended December 31, 2017 and 2016, 2016 and 2015, and 2015 and 2014 (in thousands):
Prior year December 31 net income ................................................. $
Changes (net of tax):
Increased retail non-fuel base revenues ...........................................
Effective tax rate ..............................................................................
Increased (decreased) non-base revenue, net of energy expense .....
Increased (decreased) investment and interest income ....................
Decreased allowance for funds used during construction ................
(Increased) decreased depreciation and amortization ......................
Increased taxes other than income taxes ..........................................
Increased interest on long-term debt (net of capitalized interest) ....
Other.................................................................................................
Current year December 31 net income............................................. $
2017
2016
2015
96,768
$
81,918
$
91,428
8,651 (a)
3,379 (d)
3,213 (g)
2,825 (i)
(5,303) (j)
(4,242) (m)
(3,465) (p)
(927)
(2,638)
98,261
$
28,802 (b)
(5,343) (e)
804
(2,784) (i)
(4,887) (k)
3,580 (n)
(1,168) (q)
(3,700) (r)
(454)
96,768
$
9,290 (c)
1,540 (f)
(5,370) (h)
3,084 (i)
(4,953) (l)
(4,214) (o)
(641)
(4,516) (s)
(3,730)
81,918
______________________
Footnotes reflect pre-tax amounts
(a)
Increased retail non-fuel base revenues primarily due to the non-fuel base rate increase approved in the 2017 PUCT Final
Order. 2017 included approximately $8.8 million of retail non-fuel base revenues for the period from July 18, 2017
through December 31, 2017, which was recognized when the 2017 PUCT Final Order was approved in December 2017.
Excluding the $8.8 million 2017 PUCT Final Order impact, retail non-fuel base revenues increased $4.5 million, or 0.7%,
in 2017 compared to 2016.
Increased retail non-fuel base revenues primarily due to the recognition of $40.9 million related to the 2016 PUCT Final
Order.
Retail non-fuel base revenues increased, primarily due to hotter weather in the third quarter of 2015 contributing to an
increase in kWh sales and an increase in the average number of customers.
The effective tax rate decreased primarily due to a reduction in state income taxes primarily due to audit settlements.
The effective tax rate increased due to the change to normalize state income taxes in accordance with the 2016 PUCT
Final Order and the NMPRC Final Order.
The effective tax rate decreased due to a decrease in state income taxes and an increase in decommissioning income.
These decreases were partially offset by a decrease in the allowance for equity funds used during construction ("AEFUDC")
and the loss of the domestic production activities deduction in 2015.
Non-base revenues, net of energy expenses increased due to: (i) the recognition of Palo Verde performance rewards of
$5.0 million associated with the 2013 to 2015 performance periods, net of disallowed fuel and purchased power costs
related to the resolution for the Texas fuel reconciliation proceeding designated as PUCT Docket No. 46308; (ii) an
increase of $1.1 million in other revenues primarily due to an increase in Texas miscellaneous service revenues; (iii) an
increase of $1.0 million in deregulated Palo Verde Unit 3 revenues; and (iv) an increase of $1.0 million in energy efficiency
bonuses awarded. These increases were partially offset by a decrease of $3.9 million in transmission wheeling revenues
due to the expiration of a contract.
Non-base revenues, net of energy expenses decreased due to: (i) a decrease of $5.3 million in deregulated Palo Verde
Unit 3 revenues; (ii) the recognition in 2014 of Palo Verde performance rewards of $2.2 million associated with the 2009
to 2012 performance periods, net of disallowed fuel and purchased power costs related to the resolution for the Texas
fuel reconciliation proceeding designated as PUCT Docket No. 41852; and (iii) a decrease of $0.7 million in energy
efficiency bonuses awarded. These decreases were partially offset by an increase of $1.7 million in transmission wheeling
revenues.
Investment and interest income increased in 2017, decreased in 2016 and increased in 2015, primarily due to changes in
realized gains on securities sold from the Company’s Palo Verde decommissioning trust. Sales of such securities are
primarily the result of the Company's efforts to re-balance and further diversify the trust fund investments.
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 Eastside Operations Center
("EOC") being placed in service in 2015 and 2016, and a reduction in the AFUDC rate effective January 2016 as a result
of the 2016 PUCT Final Order.
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
33
(l)
(m)
(n)
(o)
(p)
(q)
(r)
(s)
AFUDC decreased primarily due to lower balances of CWIP primarily due to MPS Units 1 and 2, and the EOC being
placed in service during the first quarter of 2015 and a reduction in the AFUDC rate.
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 2016 PUCT Final Order and the NMPRC Final Order and (ii) the sale of
the Company's interest in Four Corners in 2016. These decreases were partially offset by an increase in plant, primarily
due to MPS Units 1 and 2 and the EOC each being placed in service in March 2015, and MPS Units 3 and 4 being placed
in service in May 2016 and September 2016, respectively.
Depreciation and amortization increased due to increased depreciable plant balances including MPS Units 1 and 2 and
the EOC which began commercial operation in the first quarter of 2015, partially offset by a change in the estimated
useful life of certain large intangible software systems.
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.
Interest on long-term debt increased, primarily due to the $150.0 million principal amount of senior notes issued in March
2016.
Interest on long-term debt increased, primarily due to the $150.0 million principal amount of senior notes issued in
December 2014.
34
The following discussion includes detailed descriptions of factors affecting individual line items in the results of operations.
The amounts presented below are presented on a pre-tax basis.
Historical Results of Operations
Operating revenues
We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale
power market generally at market-based prices. Sales for resale (which are FERC regulated cost-based wholesale sales within our
service territory), accounted for less than 1% of revenues in each of 2017, 2016 and 2015.
Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment
mechanisms. Historically, a significant portion of fuel costs have been recovered through base rates in New Mexico. Effective
July 1, 2016, with the implementation of the NMPRC Final Order, fuel costs are no longer recovered through base rates. Beginning
July 1, 2016, all fuel costs are recovered through a fuel adjustment mechanism. We record deferred fuel revenues for the difference
between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. "Non-
fuel base revenues" refers to our revenues from the sale of electricity excluding such fuel costs.
Retail non-fuel base revenue percentages by customer class are presented below:
Years Ended December 31,
2017
2016
2015
Residential.............................................................................
Commercial and industrial, small .........................................
Commercial and industrial, large ..........................................
Sales to public authorities .....................................................
Total retail non-fuel base revenues ................................
46%
32
6
16
100%
46%
32
6
16
100%
44%
33
7
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 78% of our non-fuel base revenues. While this customer
base is more stable, it is also more sensitive to changes in weather conditions. The current rate structures in Texas and New Mexico
reflect higher base rates during the peak summer season of May through October and lower base rates during November through
April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh
sales and revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base
revenues derived during each quarter for the periods presented:
Years Ended December 31,
2017
2016
2015
January 1 to March 31..........................................
April 1 to June 30.................................................
July 1 to September 30.........................................
October 1 to December 31 ...................................
Total ..............................................................
18%
27
34
21
100%
17%
25
38
20
100%
18%
26
35
21
100%
Weather significantly impacts our residential, small commercial and industrial customers, and to a lesser extent, our sales to
public authorities. Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree
the average outdoor temperature varies from a standard of 65 degrees Fahrenheit, a degree day is recorded. The table below shows
heating and cooling degree days compared to a 10-year average for 2017, 2016 and 2015.
Cooling degree days ......................................
Heating degree days ......................................
2,917
1,522
2,811
1,851
2,839
2,095
2017
2016
2015
10-year
Average
2,773
2,081
35
Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew 1.7% and 1.5%
in 2017 and 2016, respectively. See the tables presented on pages 38 and 39 which provide detail on the average number of retail
customers and the related revenues and kWh sales.
Retail non-fuel base revenues. For the twelve months ended December 31, 2017, retail non-fuel base revenues increased
primarily due to the recognition of $8.8 million approved in the 2017 PUCT Final Order. Excluding the $8.8 million 2017 PUCT
Final Order impact, for the twelve months ended December 31, 2017, retail non-fuel base revenues increased $4.5 million, or
0.7%, compared to the twelve months ended December 31, 2016. This increase was primarily due to increased revenues from
residential customers of $2.5 million driven by a 1.6% increase in the average number of residential customers served and increased
revenues from small commercial and industrial customers of $2.1 million driven by a 2.4% increase in the average number of
small commercial and industrial customers served. The Company experienced an overall 1.7% increase in the average number of
customers served, partially offset by milder weather when compared to the twelve months ended December 31, 2016. Heating
degree days decreased 17.8% in the twelve months ended December 31, 2017, when compared to the twelve months ended
December 31, 2016. During our peak summer cooling season, cooling degree days in 2017 were comparable to the same period
in 2016.
For the twelve months ended December 31, 2016, retail non-fuel base revenues increased primarily due to the recognition
of $40.9 million related to the 2016 PUCT Final Order. Excluding the $40.9 million 2016 PUCT Final Order impact, for the twelve
months ended December 31, 2016, retail non-fuel base revenues increased $3.4 million, or 0.6%, compared to the twelve months
ended December 31, 2015. This increase was primarily due to increased revenues from residential customers of $3.5 million due
to a 1.3% increase in kWh sales and increased revenues from small commercial and industrial customers of $2.5 million due to a
0.8% increase in kWh sales. Increased kWh sales from residential customers and small commercial and industrial customers were
driven by a 1.4% and 1.9% increase in the average number of customers, respectively, offset in part by milder weather during the
twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015. Revenues decreased $2.4
million from large commercial and industrial customers during the twelve months ended December 31, 2016 compared to the
twelve months ended December 31, 2015 due to a 3.0% decrease in kWh sales, due primarily to reduced demand by the steel
manufacturing industry, and a decrease in surcharges billed to a large customer in 2016 compared to 2015. Revenues decreased
$0.2 million from public authority customers reflecting a 0.8% decrease in kWh sales. Cooling degree days were relatively
consistent with 2015 and were 2.9% over the 10-year average. Heating degree days decreased 11.6% in 2016, compared to 2015,
and were 14.2% below the 10-year average.
Fuel revenues. Fuel revenues consist of (i) revenues collected from customers under fuel recovery mechanisms approved
by the state commissions and the FERC, (ii) deferred fuel revenues which are comprised of the difference between fuel costs and
fuel revenues collected from customers and (iii) prior to July 1, 2016, fuel costs recovered in base rates in New Mexico. In New
Mexico, effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs are no longer
recovered through base rates, as it was historically, but are recovered through the FPPCAC. Fuel and purchased power costs are
reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. In Texas, fuel
costs are recovered through a fixed fuel factor. We can seek to revise our Texas fixed fuel factor based upon an approved formula
at least four months after our last revision, except in the month of December. In addition, if we materially over-recover fuel costs,
we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those
costs. Fuel over and under recoveries are defined as material when they exceed 4% of the previous twelve months' fuel costs.
In March 2017 and March 2016, $1.4 million and $1.6 million, respectively, were credited to customers through the applicable
fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage.
We over-recovered fuel costs by $17.1 million in the twelve months ended December 31, 2017. We under-recovered fuel
costs by $14.9 million and over-recovered fuel costs by $13.3 million in the twelve months ended December 31, 2016 and 2015,
respectively. At December 31, 2017, we had a net fuel over-recovery balance of $6.2 million, including an over-recovery of $5.8
million and $0.4 million in Texas and in New Mexico, respectively. On October 13, 2017, we filed a request to decrease our Texas
fixed fuel factor by approximately 19.0% to reflect decreased fuel expenses primarily related to a decrease in the price of natural
gas used to generate power. The decrease in our Texas fixed fuel factor became effective beginning with the November 2017
billing month and will continue thereafter until changed by the PUCT.
Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily
made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations.
We have shared 100% of margins on non-arbitrage sales (as defined by the settlement in PUCT Docket No. 41852) and 50% of
margins on arbitrage sales with our Texas customers since April 1, 2014. For the period April 1, 2014 through June 30, 2015, our
total share of margins assignable to the Texas retail jurisdiction, on arbitrage and non-arbitrage off-system sales, could not exceed
10% of the total margins assignable to the Texas retail jurisdiction on all off-system sales. We are currently sharing 90% of off-
system sales margins with our New Mexico customers, and 25% of our off-system sales margins with our sales for resale customer
under the terms of their contract.
36
Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our
native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of
off-system energy generated from lower cost generating resources. Palo Verde's availability is an important factor in realizing
these off-system sales margins.
The table below shows MWhs, sales revenue, fuel cost, total margins and retained margins made on off-system sales for the
twelve months ended December 31, 2017, 2016 and 2015 (in thousands, except for MWhs).
MWh sales .....................................
Sales revenue ................................. $
Fuel cost......................................... $
Total margins ................................. $
Retained margins ........................... $
Years Ended December 31,
2017
2,042,884
58,986
46,258
12,728
1,673
2016
1,927,508
45,702
38,933
6,769
1,137
$
$
$
$
2015
2,500,947
64,816
52,406
12,410
1,362
$
$
$
$
Off-system sales revenue increased $13.3 million, or 29.1%, and the related retained margins increased $0.5 million, or
47.1%, for the twelve months ended December 31, 2017 when compared to 2016 as a result of higher average market prices for
power and a 6.0% increase in MWh sales. Off-system sales revenue decreased $19.1 million, or 29.5%, and the related retained
margins decreased $0.2 million, or 16.5%, for the twelve months ended December 31, 2016 when compared to 2015 as a result
of lower average market prices for power and a 22.9% decrease in MWh sales.
37
Comparisons of kWh sales and operating revenues are shown below:
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 ..............................................................
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....................................................
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:
Fuel cost ........................................................................
Shared margins..............................................................
Retained margins...........................................................
Total off-system sales .................................
Other (6)................................................................................
Wheeling revenues........................................................
Miscellaneous service revenues and other (7) ..............
Total other...................................................
$
287,884
198,799
38,403
97,890
622,976
2,730
625,706
218,380
(17,133)
—
201,247
46,258
11,055
1,673
58,986
18,114
12,744
30,858
$
278,774
194,942
39,070
96,881
609,667
2,407
612,074
148,397
14,893
33,279
196,569
38,933
5,632
1,137
45,702
21,966
10,625
32,591
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
7,325
5,423
536
13,284
(3,852)
2,119
(1,733)
Average number of retail customers (8):
Total operating revenues ....................... $
916,797
$
886,936
$
29,861
Residential.............................................................................
Commercial and industrial, small .........................................
Commercial and industrial, large ..........................................
Sales to public authorities .....................................................
Total............................................................
368,044
41,978
48
5,532
415,602
362,138
41,014
49
5,303
408,504
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
18.8
96.3
47.1
29.1
(17.5)
19.9
(5.3)
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.
Represents revenues with no related kWh sales.
Includes an Energy Efficiency Bonus 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)
38
Years Ended December 31:
kWh sales (in thousands):
Retail:
2016
2015
Amount
Percent
Increase (Decrease)
Residential.....................................................................
Commercial and industrial, small .................................
Commercial and industrial, large ..................................
Sales to public authorities .............................................
Total retail sales..................................................
Wholesale:
Sales for resale ..............................................................
Off-system sales............................................................
Total wholesale sales..........................................
Total kWh sales ..........................................
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
2,771,138
2,384,514
1,062,662
1,585,568
7,803,882
63,347
2,500,947
2,564,294
10,368,176
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....................................................
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)................................
Off-system sales:
Fuel cost ........................................................................
Shared margins..............................................................
Retained margins...........................................................
Total off-system sales .................................
Other (5)................................................................................
Wheeling revenues........................................................
Miscellaneous service revenues and other (6) (7).........
Total other...................................................
$
278,774
194,942
39,070
96,881
609,667
2,407
612,074
148,397
14,893
33,279
196,569
38,933
5,632
1,137
45,702
21,966
10,625
32,591
$
246,265
187,436
40,411
91,244
565,356
2,455
567,811
127,765
(13,342)
72,129
186,552
52,406
11,048
1,362
64,816
21,002
9,688
30,690
34,651
18,933
(31,917)
(13,058)
8,609
(1,261)
(573,439)
(574,700)
(566,091)
32,509
7,506
(1,341)
5,637
44,311
(48)
44,263
20,632
28,235
(38,850)
10,017
(13,473)
(5,416)
(225)
(19,114)
964
937
1,901
Average number of retail customers (8):
Total operating revenues ....................... $
886,936
$
849,869
$
37,067
Residential.............................................................................
Commercial and industrial, small .........................................
Commercial and industrial, large ..........................................
Sales to public authorities .....................................................
Total............................................................
362,138
41,014
49
5,303
408,504
356,969
40,250
49
5,250
402,518
5,169
764
—
53
5,986
1.3%
0.8
(3.0)
(0.8)
0.1
(2.0)
(22.9)
(22.4)
(5.5)
13.2%
4.0
(3.3)
6.2
7.8
(2.0)
7.8
16.1
-
(53.9)
5.4
(25.7)
(49.0)
(16.5)
(29.5)
4.6
9.7
6.2
4.4
1.4%
1.9
-
1.0
1.5
_______________________
(1)
(2)
Includes a $40.9 million increase resulting from the 2016 PUCT Final Order.
Includes the portion of DOE refunds related to spent fuel storage of $1.6 million and $5.8 million in 2016 and 2015, respectively, that were credited to
customers through the applicable fuel adjustment clauses.
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.
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $8.7 million and $9.7 million in 2016 and 2015, respectively.
Represents revenues with no related kWh sales.
Includes $1.5 million increase resulting from the 2016 PUCT Final Order.
Includes an Energy Efficiency Bonus of $0.5 million and $1.3 million in 2016 and 2015, respectively.
The number of retail customers presented is based on the number of service locations.
(3)
(4)
(5)
(6)
(7)
(8)
39
Energy expenses
Our sources of energy include electricity generated from our nuclear and natural gas generating plants and purchased power.
After adding natural gas generating units MPS Units 1 and 2 in March 2015 and MPS Units 3 and 4 in May 2016 and September
2016, respectively, into the Company's system generating resources, Palo Verde represents approximately 30% of our net
dependable generating capacity and approximately 57% of our Company-generated energy for the twelve months ended
December 31, 2017. Fluctuations in the price of natural gas, which is also the primary factor influencing the price of purchased
power, have had a significant impact on our cost of energy.
Energy expenses increased $11.3 million, or 4.8%, for the twelve months ended December 31, 2017 compared to the twelve
months ended December 31, 2016, primarily due to increased natural gas costs of $18.4 million due to an 8.2% increase in the
MWhs generated with natural gas and a 6.2% increase in the average cost of MWhs generated. This increase in energy expenses
was partially offset by decreased coal costs of $5.6 million as a result of the sale of our interest in Four Corners, a coal-fired
generation station, in July 2016.
Energy expenses decreased $8.5 million, or 3.5%, for the twelve months ended December 31, 2016 compared to the twelve
months ended December 31, 2015, primarily due to (i) decreased natural gas costs of $10.6 million due to a 6.3% decrease in the
MWhs generated with natural gas and (ii) decreased coal costs of $7.8 million as a result of the sale of our interest in Four Corners,
a coal-fired generation station, on July 6, 2016. These decreases in energy expenses were partially offset by (i) increased total
purchased power of $6.2 million due to an 11.6% increase in the MWhs purchased and (ii) increased nuclear fuel expense of $3.7
million due to a $4.6 million reduction in the 2016 DOE refund compared to 2015.
The table below details the sources and costs of energy for 2017, 2016 and 2015.
2016
MWh
Cost per
MWh
Cost
(in thousands)
123,806
$
6,154 (a)
43,778 (b)
173,738
$
3,550,904
175,258
5,093,844
8,820,006
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
Fuel Type
Cost
Natural Gas ................... $
Coal...............................
Nuclear..........................
Total.......................
(in thousands)
142,227
575 (a)
42,267 (b)
185,069
Purchase Power:
Photovoltaic...........
Other ......................
Total purchased power..
Total energy ........... $
23,784
35,898
59,682
244,751
Fuel Type
Cost
Natural Gas ................... $
Coal...............................
Nuclear..........................
Total.......................
(in thousands)
134,361
13,913
40,126 (b)
188,400
Purchase Power:
Photovoltaic...........
Other ......................
Total purchased power ..
Total energy ........... $
22,495
31,050
53,545
241,945
2017
MWh
Cost per
MWh
$
3,841,550
—
5,109,325
8,950,875
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
2015
MWh
Cost per
MWh
$
3,790,659
657,744
5,136,686
9,585,089
277,241
1,113,705
1,390,946
10,976,035
35.45
21.15
9.06
20.32
81.14
27.88
38.50
22.63
_____________________
(a) The sale of our interest in Four Corners, a coal-fired generation station, closed on July 6, 2016. The cost includes the amortization of
deferred coal mine reclamation obligations.
(b) Costs includes a DOE refund related to spent fuel storage of $1.6 million, $1.8 million, and $6.4 million recorded in 2017, 2016, and
2015, respectively. Cost per MWh excludes these refunds.
40
Other operations expense
Other operations expense increased $0.6 million, or 0.3%, in 2017 compared to 2016, primarily due to a $4.1 million increase
in Palo Verde administrative and general ("A&G") expenses in 2017 compared to 2016, and a $3.0 million increase in various
other operating costs. This increase was partially offset by a $6.5 million decrease in operating costs as a result of the sale of our
interest in Four Corners in July 2016.
Other operations expense decreased $0.9 million, or 0.4%, in 2016 compared to 2015, primarily due to (i) a $2.7 million
decrease in pension and benefits costs due to an amendment to the other post-retirement benefit plan and changes in actuarial
assumptions used to calculate expenses for the post-retirement benefit plans, partially offset by higher medical and other employee
benefit costs, (ii) decreased operations expense of $0.9 million at our fossil-fuel generating plants, primarily due to lower operating
costs as a result of the sale of our interest in Four Corners in July 2016 offset by increased operating expenses at MPS, and (iii)
decreased other A&G expenses of $0.5 million. These decreases were partially offset by (i) a $2.3 million increase in regulatory
expenses, primarily related to the portion of the 2015 New Mexico and Texas rate cases that were expensed, and (ii) increased
transmission and distribution expenses of $0.8 million.
Maintenance expense
Maintenance expense increased $2.7 million, or 4.1%, in 2017 compared to 2016, primarily due to a $7.1 million increase
in maintenance outages at Newman Units 1, 3, & 4, and a $3.9 million increase in routine maintenance at Newman and MPS.
These increases were offset by a $5.6 million decrease in maintenance costs as a result of the sale of our interest in Four Corners
in July 2016 and a $1.7 million decrease in Palo Verde maintenance costs. Maintenance expense increased $1.5 million, or 2.3%,
in 2016 compared to 2015, primarily due to an increase in the level of maintenance at Rio Grande and a planned outage at Four
Corners, which was partially offset by a decrease in maintenance at Newman.
Depreciation and amortization expense
Depreciation and amortization expense increased $6.5 million or 7.7%, in 2017 compared to 2016, primarily due to increases
in plant, including MPS Units 3 and 4, which were placed in service in May 2016 and September 2016, respectively. These increases
were partially offset by the sale of the Company's interest in Four Corners in July 2016.
Depreciation and amortization expense decreased $5.5 million or 6.1%, in 2016 compared to 2015, primarily due to reductions
of approximately $10.9 million resulting from changes in depreciation rates approved in the 2016 PUCT Final Order and the
NMPRC Final Order, and the sale of the Company's interest in Four Corners in July 2016. These decreases were partially offset
by an increase in plant, primarily due to MPS Units 1 and 2 and the EOC being placed in service in March 2015, and MPS Units
3 and 4 being placed in service in 2016.
Taxes other than income taxes
Taxes other than income taxes increased $5.3 million, or 8.1%, in 2017 compared to 2016, primarily due to increased property
tax rates and valuations in Texas as a result of MPS Units 3 and 4 being placed in service in 2016 and increased billed revenues
in Texas. Taxes other than income taxes increased $1.8 million, or 2.8%, in 2016 compared to 2015, primarily due to increased
property tax rates and valuations in Texas as a result of MPS Units 1 and 2 and the EOC being placed in service during the first
quarter of 2015 and increased billed revenues in Texas. These increases were partially offset by decreased property taxes in Arizona
due to decreased property values.
Other income (deductions)
Other income (deductions) decreased $0.3 million, or 1.7%, in 2017 compared to 2016, primarily due to decreased AEFUDC
resulting from lower average balances of CWIP and a reduction in the AEFUDC rate. This decrease was partially offset by increased
investment and interest income due to higher realized gains in our decommissioning trust funds.
Other income (deductions) decreased $7.2 million, or 27.8%, in 2016 compared to 2015, primarily due to (i) decreased
AEFUDC resulting from lower average balances of CWIP and a reduction in the AEFUDC rate, and (ii) decreased investment
and interest income due to lower realized gains from our decommissioning trust funds.
41
Interest charges (credits)
Interest charges (credits) increased by $4.5 million, or 7.1%, in 2017 compared to 2016, primarily due to decreased allowance
for borrowed funds used during construction ("ABFUDC") as a result of lower average balances of CWIP and a reduction in the
ABFUDC rate and interest expense on the $150.0 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in
March 2016.
Interest charges (credits) increased by $7.6 million, or 13.8%, in 2016 compared to 2015 primarily due to interest expense
on the $150.0 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in March 2016 and decreased ABFUDC
as a result of lower balances of CWIP and a reduction in the ABFUDC rate.
Income tax expense
Income tax expense decreased by $2.9 million, or 5.4%, in 2017 compared to 2016, primarily due to a decrease in state
income tax due to audit settlements in Texas and Arizona. Income tax expense increased by $19.0 million, or 54.5%, in 2016
compared to 2015, primarily due to (i) an increase in the pre-tax income, (ii) an increase in state income taxes due to normalization
as discussed in Note J of the Notes to Financial Statements and (iii) decreases in decommissioning trust income, which is taxed
at a lower rate.
New accounting standards
In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718) Improvements to Employee
Share-Based Payment Accounting to simplify the accounting for share-based payment transactions, including the income tax
consequences, classification of awards either as equity or liabilities, and classification on the statements of cash flows. We adopted
the new standard effective January 1, 2017. The adoption of the new standard did not have a material impact on our financial
condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard was to increase net
operating loss carryforward deferred tax assets and retained earnings by $0.2 million on January 1, 2017.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) to provide a framework
that replaces the existing revenue recognition guidance, and has since modified the standard with several ASUs. The standard
provides that an entity should recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods
or services to customers. More specifically, the standard requires entities to recognize revenue through the application of a five-
step model, which includes the: (i) identification of the contract; (ii) identification of the performance obligations; (iii) determination
of the transaction price; (iv) allocation of the transaction price to the performance obligations; and (v) the recognition of revenue
as the entity satisfies the performance obligations. We will adopt the new standard for reporting periods beginning on January 1,
2018, and intend use the modified retrospective approach.
We have analyzed the impact of the new standard on our various revenue and cash flow streams, and the impact on changes
to business processes, systems and controls to support recognition under the new guidance. Tariff sales to customers are determined
to be in the scope of the new standard and represent a significant portion of our total operating revenues. We have determined that
the timing or pattern of revenue recognition from tariff sales will not change. Implementation of the new standard will also not
significantly change the timing or pattern of revenue recognition from other revenue streams. Upon adoption of the standard, we
expect our disclosures to disaggregate revenues primarily by tariff based categories and off-system sales.
In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and
Measurement of Financial Assets and Liabilities to enhance the reporting model for financial instruments by addressing certain
aspects of recognition, measurement, presentation, and disclosure. ASU 2016-01 generally requires entities to measure equity
investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any
changes in fair value in net income. The guidance for classifying and measuring investments in debt securities and loans is not
changed by this ASU, but requires entities to record changes in other comprehensive income. Financial assets and financial liabilities
must be separately presented by measurement category on the balance sheet or in the accompanying notes to the financial statements.
ASU 2016-01 clarifies the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in
combination with the entity's other deferred tax assets. The provisions of this ASU become effective for reporting periods beginning
after December 15, 2017. Upon adoption of the new standard, we expect to record the cumulative effects as of January 1, 2018
which will result in a net reduction to accumulated other comprehensive income of $41.0 million, net of tax, and a corresponding
increase in retained earnings for unrealized gains (losses) related to equity securities owned by us.
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
42
the distinction under previous leases guidance for capital leases and operating leases. The impact of leases reported in our operating
results and statement of cash flows are expected to be similar to previous GAAP. ASU 2016-02 requires the recognition in the
statement of financial position, by the lessee, of a liability to make lease payments (the lease liability) and a right-of-use asset
representing its right to use the underlying asset for the lease term. How leases are recorded in regard to financial position represents
a significant change from previous GAAP guidance. The lessee is permitted to make an accounting policy election to not recognize
lease assets and lease liabilities for short-term leases. Implementation of the standard will be required for reporting periods beginning
after December 15, 2018. Adoption of the new lease accounting standard will require us to apply the new standard to the earliest
period using a modified retrospective approach. We are currently in the process of evaluating the impact of the new standard,
which includes continuing to monitor activities of the FASB, including the impact of the recently issued ASU 2018-01, and the
proposed project to allow entities to adopt the standard with a cumulative effect adjustment as of the beginning of the adoption
year, while maintaining prior year comparative financial information and disclosures as reported. ASU 2018-01, Land Easement
Practical expedient for Transition to Topic 842, provides an optional practical expedient to not evaluate existing or expired land
easements under Topic 842, if those land easements were not previously accounted for as leases under Accounting Standards
Codification Topic 840. We currently anticipate that we will apply the practical expedient under ASU 2018-01 to our existing or
expired land easements as part of our transition to Topic 842. Our evaluation process also includes evaluating the impact, if any,
on changes to business processes, systems and controls to support recognition and disclosure under the new guidance; however,
at this time we are unable to determine the impact this standard will have on the financial statements and related disclosures.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326). ASU 2016-13 changes
how companies measure and recognize credit impairment for many financial assets. The new current expected credit loss model
will require companies to immediately recognize an estimate of credit losses expected to occur over the remaining life of the
financial assets that are in the scope of the standard. The ASU also makes targeted amendments to the current impairment model
for available-for-sale debt securities. The provisions of ASU 2016-13 will be required for reporting periods beginning after
December 15, 2019. ASU 2016-13 will be applied in a modified retrospective approach through a cumulative-effect adjustment
to retained earnings as of the beginning of the first reporting period in which the guidance is implemented. We are currently
assessing the future impact of ASU 2016-13.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts
and Cash Payments to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement
of cash flows. The provisions of ASU 2016-15 will be required for reporting periods beginning after December 15, 2017. ASU
2016-15 will be applied using a retrospective transition method to each period presented. If it is impracticable to apply ASU
2016-15 retrospectively for some of the issues, the amendments for those issues may be applied prospectively as of the earliest
date practicable. We are currently assessing the future impact of this ASU.
In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits (Topic 715) Improving the Presentation
of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. ASU 2017-07 amends Accounting Standards
Codification 715, Compensation - Retirement Benefits, to require companies to present the service cost component of net benefit
cost in the income statement line items where compensation cost is reported. Companies will present all other components of net
benefit cost separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In
addition, only the service cost component will be eligible for capitalization in assets. The amendments in ASU 2017-07 will be
required for reporting periods beginning after December 15, 2017. The amendments in ASU 2017-07 should be applied
retrospectively for the income statement presentation of the service cost component and the other components of net benefit costs
and prospectively, on and after the effective date, for the capitalization of the service cost component. We expect that the retrospective
impact of implementing this ASU on the Statement of Operations for the twelve months ended December 31, 2017 would be an
increase in (i) Other operations of $8.2 million, (ii) Other interest of $15.8 million, (iii) Miscellaneous non-operating income of
$32.4 million, and (iv) Miscellaneous non-operating deductions of $8.4 million.
In May 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718), Scope of Modification
Accounting, to provide guidance about when to account for a change to the terms or conditions of a share-based payment award
as a modification. Under ASU 2017-09, modification accounting is required only if the fair value, the vesting conditions, or the
classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The amendments of
ASU 2017-09 will be required for reporting periods beginning after December 15, 2017. ASU 2017-09 should be applied
prospectively to an award modified on or after the adoption date. We are assessing the future impact of ASU 2017-09; however,
we currently do not expect the impact of this ASU to be significant to our financial conditions, results of operations or cash flows.
In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220) as a
result of concerns raised by stakeholders due to the TCJA. More specifically, the concerns raised are that because the adjustment
due to the reduction of the historical corporate income tax rate of 35% to the newly enacted corporate income tax rate of 21% is
required to be made for accumulated deferred income taxes, the tax effect of items within accumulated other comprehensive
income (“AOCI”) do not reflect the appropriate tax rate under current accounting standards which would result in "stranded taxes".
43
ASU 2018-02 allows companies to reclassify stranded taxes from AOCI to retained earnings. The amount of the reclassification
would be the difference between the historical corporate income tax rate of 35% and the newly enacted 21% corporate income
tax rate. The provisions of ASU 2018-02 are effective for fiscal years and interim periods within that reporting period beginning
after December 15, 2018. Early adoption is permitted, including adoption in any interim periods for reporting periods for which
financial statements have not been issued. We are currently in the process of evaluating the impact of ASU 2018-02 and its impact
on regulated utilities. At December 31, 2017, we have $7.2 million in stranded taxes in AOCI.
Inflation
For the last several years, inflation has been relatively low and, therefore, has had little impact on our results of operations
and financial condition.
Liquidity and Capital Resources
We continue to maintain a strong balance of common stock equity in our capital structure, which supports our bond ratings,
allowing us to obtain financing from the capital markets at a reasonable cost. At December 31, 2017, our capital structure, including
common stock, long-term debt, current maturities of long-term debt, and short-term borrowings under our RCF, consisted of 45.5%
common stock equity and 54.5% debt. As of December 31, 2017, we had a balance of $7.0 million of cash and cash equivalents.
Based on current projections, we believe that we will have adequate liquidity through the issuance of long-term debt, our current
cash balances, cash from operations and available borrowings under our RCF to meet all of our anticipated cash requirements for
the next twelve months.
Our principal liquidity requirements in the near-term are expected to consist of capital expenditures to expand and support
electric service obligations, expenditures for nuclear fuel inventory, interest payments on our indebtedness, cash dividend payments,
operating expenses including fuel costs, maintenance costs, security, compliance initiative and taxes.
Capital Requirements. During the twelve months ended December 31, 2017, our capital requirements primarily consisted
of expenditures for the construction and purchase of electric utility plant, debt retirements, payments of common stock dividends,
and purchases of nuclear fuel. Projected utility construction expenditures are to add new generation, expand and update our
transmission and distribution systems, make capital improvements and replacements at Palo Verde and other generating facilities,
and make investments in other property and equipment. Estimated cash construction expenditures for all capital projects for 2018
are expected to be approximately $236 million. See Part I, Item 1, "Business - Construction Program." Cash capital expenditures
for new electric plant were $190.3 million, net of insurance proceeds, in the twelve months ended December 31, 2017 compared
to $225.4 million in the twelve months ended December 31, 2016. Capital requirements for purchases of nuclear fuel were $38.5
million for the twelve months ended December 31, 2017, as compared to $42.4 million for the twelve months ended December
31, 2016.
On December 29, 2017, we paid a quarterly cash dividend of $0.335 per share, or $13.6 million, to shareholders of record
as of the close of business on December 15, 2017. We paid a total of $53.3 million in cash dividends during the twelve months
ended December 31, 2017. On February 1, 2018, our Board of Directors declared a quarterly cash dividend of $0.335 per share
payable on March 30, 2018 to shareholders of record as of the close of business on March 16, 2018. Typically, the Board of
Directors reviews the Company's dividend policy annually in the second quarter of each year. In addition, while we do not currently
anticipate repurchasing shares of our common stock in 2018, we may repurchase shares of our common stock in the future. Under
our repurchase program, purchases can be made at open market prices or in private transactions, and repurchased shares are
available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were
repurchased during the twelve months ended December 31, 2017. As of December 31, 2017, a total of 393,816 shares remain
eligible for repurchase under the repurchase program.
We expect to continue to maintain a prudent level of liquidity and monitor market conditions for debt and equity securities.
We primarily utilize the distribution of dividends to maintain a balanced capital structure and supplement this effort with share
repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing
to make investments in new electric plant and other assets in order to reliably serve our customers.
Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced
by the timing of revenues and expenses recognized for income tax purposes. The following summary describes the major impacts
of the TCJA on our liquidity. We continue to evaluate the TCJA and have made assumptions based on information currently
available.
The TCJA discontinued bonus depreciation for regulated utilities for property acquired and placed in service after September
27, 2017, which discontinuance will reduce the tax deductions previously available to us for 2017, 2018 and 2019. The decrease
44
in tax deductions will result in the utilization of our net operating loss carryforwards (“NOL carryforwards”) approximately two
years earlier than anticipated and is expected to result in higher income tax payments beginning in 2019, after the full utilization
of NOL carryforwards. However, due to the lower federal corporate income tax rate enacted by the TCJA, our future federal
corporate income tax payments will be made at the reduced rate of 21% beginning in 2018. Due to NOL carryforwards, minimal
tax payments are expected for 2018, which are mostly related to state income taxes.
However, we expect that the effect of the TCJA on our rates will be beneficial to our customers. Following the enactment
of the TCJA and the reduction of the federal corporate income tax rate, revenues collected from our customers in 2018 will be
reduced in an amount that approximates the savings in tax expense. This reduction in revenues is expected to negatively impact
our cash flows by approximately $26 million to $31 million during 2018.
We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans, and
decommissioning trust funds. We contributed $9.8 million and $9.2 million to our retirement plans during both the twelve months
ended December 31, 2017 and 2016, respectively. We contributed $0.5 million and $1.7 million to our other post-retirement benefit
plans during the twelve months ended December 31, 2017 and 2016, respectively. We contributed $3.8 million and $4.5 million
to our decommissioning trust funds in 2017 and 2016, respectively. We are in compliance with the funding requirements of the
federal government for our benefit plans. In addition, with respect to our nuclear plant decommissioning trust, we are in compliance
with the funding requirements of the federal law and the ANPP Participation Agreement. We will continue to review our funding
for these plans in order to meet our future obligations.
In 2010, we and the RGRT, a Texas grantor trust through which we finance our portion of fuel for Palo Verde, entered into
a note purchase agreement with various institutional purchasers. Under the terms of the agreement, RGRT sold to the purchasers
$110.0 million aggregate principal amount of senior notes. In August 2015 and 2017, $15.0 million and $50.0 million, respectively,
of these senior notes matured and were paid with borrowings under the RCF.
Capital Resources. Cash provided by operations, $288.6 million for the twelve months ended December 31, 2017 and $231.2
million for the twelve months ended December 31, 2016, is a significant source for funding capital requirements. The primary
factors affecting the change in cash flows from operations were the change in net over-collection and under-collection of fuel
revenues and accounts receivable. Cash from operations has been impacted by the timing of the recovery of fuel costs through
fuel recovery mechanisms in Texas and New Mexico, and our sales for resale customer. We recover actual fuel costs from customers
through fuel adjustment mechanisms in Texas and New Mexico, and from our sales for resale customer. We record deferred fuel
revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In
Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor at least four months after
our last revision except in the month of December based upon our approved formula which allows us to adjust fuel rates to reflect
changes in costs of natural gas. We are required to request to refund fuel costs in any month when the over-recovery balance
exceeds a threshold material amount and we expect fuel costs to continue to be materially over-recovered. We are permitted to
seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount that we expect fuel cost
recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed
4% of the previous twelve months' fuel costs. On October 13, 2017, we filed a request to decrease our Texas fixed fuel factor by
approximately 19% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate
power. The decrease in our Texas fixed fuel factor became effective with the November 2017 billing month and will continue
thereafter until changed by the PUCT. During the twelve months ended December 31, 2017, we had over-recoveries of fuel costs
of $17.1 million compared to under-recoveries of fuel costs of $14.9 million during the twelve months ended December 31, 2016.
At December 31, 2017, we had a net fuel over-recovery balance of $6.2 million, including an over-recovery of $5.8 million in the
Texas jurisdiction and an over-recovery of $0.4 million in the New Mexico jurisdiction.
We maintain the RCF for working capital and general corporate purposes and financing nuclear fuel through RGRT. RGRT,
the trust through which we finance our portion of nuclear fuel for Palo Verde, is consolidated in our financial statements. On
January 9, 2017, we exercised our option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the
size of the facility by $50.0 million to $350.0 million. We still have the option to extend the facility by one additional year to
January 2021 and to increase the RCF by up to $50.0 million (up to a total of $400.0 million) upon the satisfaction of certain
conditions including obtaining commitments from lenders or third party financial institutions. In August 2017, RGRT's $50.0
million Series B 4.47% Senior Notes matured and were paid utilizing funds borrowed under the RCF. The total amount borrowed
for nuclear fuel by RGRT, excluding debt issuance costs, was $133.5 million at December 31, 2017, of which $88.5 million had
been borrowed under the RCF, and $45.0 million was borrowed through the issuance of senior notes. At December 31, 2016, the
total amounts borrowed for nuclear fuel by RGRT, excluding debt issuance costs, were $132.6 million of which $37.6 million had
been borrowed under the RCF and $95.0 million was borrowed through the issuance of senior notes. Interest costs on borrowings
to finance nuclear fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered through fuel recovery
charges. In September 2017, the $33.3 million 2012 Series A 1.875% Pollution Control Bonds which were subject to mandatory
tender for purchase were redeemed and retired utilizing funds borrowed under the RCF. The outstanding balance for working
45
capital and general corporate purposes was $85.0 million at December 31, 2017 and $44.0 million at December 31, 2016. Total
aggregate borrowings under the RCF as of December 31, 2017 were $173.5 million with an additional $176.4 million available
to borrow.
We received approval from the NMPRC on October 7, 2015, to guarantee the issuance of up to $65.0 million of long-term
debt by the RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations, which remains
effective. We received additional approval from the NMPRC on October 4, 2017 to amend and extend the RCF, issue up to $350.0
million in long-term debt and to redeem and refinance the $63.5 million 2009 Series A 7.25% Pollution Control Bonds and the
$37.1 million 2009 Series B 7.25% Pollution Control Bonds, which have optional redemptions in 2019. The NMPRC approval
to issue up to $350.0 million in long-term debt supersedes its prior approval. We requested similar approval from the FERC on
September 1, 2017 and received approval on October 31, 2017. The approval requested from the FERC also includes requests to
guarantee the issuance of up to $65.0 million of long-term debt by the RGRT and to continue to utilize our existing RCF with the
ability to amend and extend the RCF at a future date. The authorization approved by the FERC is effective from November 15,
2017 through November 14, 2019 and supersedes prior FERC approvals.
46
Contractual Obligations. Our contractual obligations as of December 31, 2017 are as follows (in thousands):
Revolving credit facility (4)
178,061
178,061
Payments due by period
Total
2018
2019 and
2020
2021 and
2022
2023 and
Beyond
$ 2,080,375
$
55,200
$
110,400
$
260,400
$ 1,654,375
390,578
51,804
9,959
2,268
19,918
49,536
19,918
340,783
—
—
—
71,474
16,581
—
4,264
1,270
—
—
—
189,946
19,260
—
49,041
6,557
—
—
68,875
22,485
—
4,264
1,713
17,282
17,282
373,814
77,554
9,904
59,701
10,491
43,519
19,228
9,904
2,132
951
Long-term debt (including interest):
Senior notes (1)
Pollution control bonds (2)
RGRT senior notes (3)
Financing obligations (including interest):
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)
$ 3,249,564
$
338,504
$
277,191
$
373,907
$ 2,259,962
We have four outstanding issuances of senior notes. In May 2005, we issued $400.0 million aggregate principal amount
of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150.0 million aggregate principal amount of 7.5%
Senior Notes due March 15, 2038. In December 2012, we issued $150.0 million aggregate principal amount of 3.3%
Senior Notes due December 15, 2022. In December 2014, we issued $150.0 million aggregate principal amount of 5.0%
Senior Notes due December 1, 2044. In March 2016, we issued an additional $150.0 million aggregate principal amount
of 5.0% Senior Notes due December 1, 2044, for a total principal amount outstanding of 5.0% Senior Notes due December
1, 2044 of $300.0 million.
We have three series of pollution control bonds outstanding that are scheduled for remarketing and/or mandatory tender
two in 2040, and one in 2042. In September 2017, the $33.3 million 2012 Series A 1.875% pollution control bonds, which
were subject to mandatory tender for purchase, were redeemed and retired utilizing funds borrowed under the RCF.
In 2010, the Company and RGRT entered into a note purchase agreement for $110.0 million aggregate principal amount
of senior notes consisting of: (a) $15.0 million aggregate principal amount of 3.67% RGRT Senior Notes, Series A, which
matured and were repaid on August 15, 2015; (b) $50.0 million aggregate principal amount of 4.47% RGRT Senior Notes,
Series B, which matured and were repaid on August 15, 2017; and (c) $45.0 million aggregate principal amount of 5.04%
RGRT Senior Notes, Series C, due August 15, 2020.
This reflects obligations outstanding under the $350.0 million RCF. At December 31, 2017, $85.0 million was borrowed
for working capital and general corporate purposes and $88.5 million was borrowed by RGRT for nuclear fuel. This
balance includes interest based on actual interest rates at the end of 2017 and assumes this amount will be outstanding
for the entire year of 2018.
Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2017. Gas
obligation includes a gas storage contract and a gas transportation contract.
Some of the nuclear fuel contracts are based on a fixed price, adjusted for a market index. The index used here is the
index at the end of 2017.
This obligation is based on our expected contributions and includes our minimum contractual funding requirements for
the non-qualified retirement income plan and the other post-retirement benefits for 2018. We have no minimum cash
contractual funding requirement related to our retirement income plan or other post-retirement benefits for 2018. However,
we are subject to minimum funding requirements of ERISA. We also may decide to fund at higher levels and expect to
contribute $9.9 million to our retirement plans in 2018. Minimum funding requirements for 2019 and beyond are not
included due to the uncertainty of the applicable interest rates and the related return on assets.
This obligation is based on the decommissioning funding allowed in PUCT Docket No. 46831, effective August 1, 2017.
We have no minimum funding obligation in the New Mexico jurisdiction effective July 1, 2016 with NMPRC Case No.
(2)
(3)
(4)
(5)
(6)
(7)
(8)
47
(9)
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.
48
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
The following discussion regarding our market-risk sensitive instruments contains forward-looking information involving
risks and uncertainties. The statements regarding potential gains and losses are only estimates of what could occur in the future.
Actual future results may differ materially from those estimates presented due to the characteristics of the risks and uncertainties
involved.
We are exposed to market risk due to changes in interest rates, equity prices and commodity prices. Substantially all financial
instruments and positions we hold are for purposes other than trading and are described below.
Interest Rate Risk
Our long-term debt obligations are all fixed-rate obligations, except for the RCF, which is based on floating rates.
To the extent the RCF is utilized for nuclear fuel purchases, interest rate risk, if any, related to the RCF is substantially
mitigated through the operation of the PUCT and the NMPRC rules, which establish energy cost recovery clauses. Under these
rules, actual energy costs, including interest expense on nuclear fuel financing, are recovered from our customers.
Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We
face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and
which were valued at $130.2 million and $119.9 million as of December 31, 2017 and 2016, respectively. A hypothetical 10%
increase in interest rates would reduce the fair values of these funds by $1.6 million and $1.4 million at December 31, 2017 and
2016, respectively.
Equity Price Risk
Our decommissioning trust funds include marketable equity securities of approximately $149.8 million and $129.8 million
at December 31, 2017 and 2016, respectively. A hypothetical 20% decrease in equity prices would have reduced the fair values
of these funds by $30.0 million and $26.0 million based on their fair values at December 31, 2017 and 2016, respectively. Declines
in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum
funding requirements. We do not expect to expend monies held in trust before 2044 or a later period when decommissioning of
Palo Verde begins.
Commodity Price Risk
We utilize contracts of various durations for the purchase of natural gas and uranium concentrates to effectively manage our
available fuel portfolio. These agreements contain variable pricing provisions and are settled by physical delivery. The fuel contracts
with variable pricing provisions, as well as substantially all of our purchased power requirements, are exposed to fluctuations in
prices due to unpredictable factors, including weather and various other worldwide events, which impact supply and demand.
However, our exposure to fuel and purchased power price risk is substantially mitigated through the operation of the PUCT and
NMPRC rules and our fuel clauses, as discussed previously.
In the normal course of business, we enter into contracts of various durations for the forward sales and purchases of electricity
to effectively manage our available generating capacity and supply needs. Such contracts include forward contracts for the sale
of generating capacity and energy during periods when our available power resources are expected to exceed the requirements of
our retail native load and sales for resale. We also enter into forward contracts for the purchase of wholesale capacity and energy
during periods when the market price of electricity is below our expected incremental power production costs or to supplement
our generating capacity when demand is anticipated to exceed such capacity. As of January 31, 2018, we had entered into forward
sales and purchase contracts for energy as discussed in Part I, Item 1, "Business – Energy Sources – Purchased Power." These
agreements are generally fixed-priced contracts that qualify for the "normal purchases and normal sales" exception provided in
the FASB guidance for accounting for derivative instruments and hedging activities and are not recorded at their fair value in our
financial statements. Because of the operation of the PUCT and the NMPRC rules and our fuel clauses, these contracts do not
expose us to significant commodity price risk.
49
Management Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial
reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities
Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal
financial officers and affected by the Company’s board of directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles and includes those policies and procedures that:
•
•
•
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions
of the assets of the Company;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and the receipts and expenditures of the Company are being
made only in accordance with authorizations of management and directors of the Company; and
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of
the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of
December 31, 2017. In making this assessment, the Company’s management used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission's 2013 Internal Control - Integrated Framework. Based on its assessment,
management believes that, as of December 31, 2017, the Company’s internal control over financial reporting is effective based
on those criteria.
The Company’s independent registered public accounting firm, KPMG LLP, has issued an audit report on the Company’s
internal control over financial reporting. This report appears on page 52 of this report.
50
Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm ...................................................................................................
Balance Sheets as of December 31, 2017 and 2016................................................................................................................
Statements of Operations for the years ended December 31, 2017, 2016 and 2015...............................................................
Statements of Comprehensive Operations for the years ended December 31, 2017, 2016 and 2015 ....................................
Statements of Changes in Common Stock Equity for the years ended December 31, 2017, 2016 and 2015.........................
Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015 .............................................................
Notes to Financial Statements.................................................................................................................................................
Page
52
53
55
56
57
58
59
51
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
El Paso Electric Company:
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying balance sheets of El Paso Electric Company (the "Company") as of December 31, 2017 and
2016, and the related statements of operations, comprehensive operations, changes in common stock equity, and cash flows for each
of the years in the three-year period ended December 31, 2017, and the related notes (collectively, the "financial statements"). We
also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company
as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three-year period
ended December 31, 2017, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial
reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying
Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s
financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public
accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to
be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error
or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining,
on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also include evaluating the
accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the
financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being
made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes
in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
We have served as the Company’s auditor since 1983.
Houston, Texas
February 28, 2018
52
EL PASO ELECTRIC COMPANY
BALANCE SHEETS
Utility plant:
ASSETS
(In thousands)
December 31,
2017
2016
Electric plant in service ........................................................................................................... $ 3,982,095
(1,320,175)
Less accumulated depreciation and amortization....................................................................
2,661,920
Net plant in service...........................................................................................................
146,059
Construction work in progress.................................................................................................
$ 3,791,566
(1,244,332)
2,547,234
154,738
Nuclear fuel; includes fuel in process of $59,689 and $57,315, respectively .........................
Less accumulated amortization ...............................................................................................
Net nuclear fuel ................................................................................................................
Net utility plant .......................................................................................................
194,933
(74,475)
120,458
194,842
(75,602)
119,240
2,928,437
2,821,212
Current assets:
Cash and cash equivalents .......................................................................................................
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,300
and $2,156, respectively ..........................................................................................................
Inventories, at cost...................................................................................................................
Under-collection of fuel revenues ...........................................................................................
Prepayments and other ............................................................................................................
Total current assets .................................................................................................
Deferred charges and other assets:
Decommissioning trust funds ..................................................................................................
Regulatory assets .....................................................................................................................
Other ........................................................................................................................................
Total deferred charges and other assets ..................................................................
399,134
Total assets...................................................................................................... $ 3,484,363
6,990
88,585
50,910
—
10,307
156,792
286,866
96,036
16,232
8,420
88,452
47,216
11,123
8,988
164,199
255,708
118,861
16,298
390,867
$ 3,376,278
See accompanying notes to financial statements.
53
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, 65,694,829 and
65,685,615 shares issued, and 133,859 and 137,017 restricted shares, respectively .............. $
Capital in excess of stated value..............................................................................................
Retained earnings ....................................................................................................................
Accumulated other comprehensive income (loss), net of tax..................................................
Treasury stock, 25,244,350 and 25,304,914 shares, respectively, at cost ...............................
Common stock equity.......................................................................................................
Long-term debt, net of current portion ....................................................................................
Total capitalization..................................................................................................
Current liabilities:
Current maturities of long-term debt.......................................................................................
Short-term borrowings under the revolving credit facility......................................................
Accounts payable, principally trade ........................................................................................
Taxes accrued ..........................................................................................................................
Interest accrued........................................................................................................................
Over-collection of fuel revenues .............................................................................................
Other ........................................................................................................................................
Total current liabilities............................................................................................
Deferred credits and other liabilities:
Accumulated deferred income taxes .......................................................................................
Accrued pension liability.........................................................................................................
Accrued post-retirement benefit liability.................................................................................
Asset retirement obligation......................................................................................................
Regulatory liabilities ...............................................................................................................
Other ........................................................................................................................................
Total deferred credits and other liabilities ..............................................................
Commitments and contingencies
December 31,
2017
2016
$
65,829
326,117
1,159,667
11,058
1,562,671
(420,506)
1,142,165
1,195,988
2,338,153
65,823
322,643
1,114,561
(7,116)
1,495,911
(421,515)
1,074,396
1,195,513
2,269,909
—
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
83,143
81,574
62,953
32,488
13,287
255
29,709
303,409
555,066
92,768
34,400
81,800
18,435
20,491
802,960
Total capitalization and liabilities ................................................................ $ 3,484,363
$ 3,376,278
See accompanying notes to financial statements.
54
EL PASO ELECTRIC COMPANY
STATEMENTS OF OPERATIONS
(In thousands except for share data)
Operating revenues ............................................................................................. $
Energy expenses:
Fuel ................................................................................................................
Purchased and interchanged power................................................................
Operating revenues net of energy expenses ......................................................
Other operating expenses:
Years Ended December 31,
2017
2016
2015
916,797
$
886,936
$
849,869
185,069
59,682
244,751
672,046
173,738
59,727
233,465
653,471
188,400
53,545
241,945
607,924
Other operations.............................................................................................
242,628
242,014
242,950
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.
69,458
90,843
70,863
473,792
198,254
3,025
17,757
715
(3,125)
18,372
72,970
2,388
(5,022)
(2,975)
67,361
149,265
51,004
98,261
2.42
2.42
1.315
$
$
$
$
66,746
84,317
65,533
458,610
194,861
7,023
14,083
1,292
(3,699)
18,699
71,544
1,303
(4,990)
(4,983)
62,874
150,686
53,918
96,768
2.39
2.39
1.225
$
$
$
$
65,223
89,824
63,736
461,733
146,191
10,639
17,508
2,062
(4,328)
25,881
65,851
1,313
(4,968)
(6,937)
55,259
116,813
34,895
81,918
2.03
2.03
1.165
40,414,556
40,350,688
40,274,986
40,535,191
40,408,033
40,308,562
55
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,
2017
2016
2015
98,261
$
96,768
$
81,918
Net gain (loss) arising during period ...........................................................
Prior service benefit.....................................................................................
12,634
—
(20,053)
32,697
Reclassification adjustments included in net income for amortization of:
Prior service benefit ...........................................................................
Net loss...............................................................................................
Net unrealized gains/losses on marketable securities:
Net holding gains (losses) arising during period.........................................
Reclassification adjustments for net gains included in net income.............
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income ...
Total other comprehensive income (loss) before income taxes..........................
Income tax benefit (expense) related to items of other comprehensive income
(loss):
Unrecognized pension and post-retirement benefit costs............................
Net unrealized (gains) losses on marketable securities ...............................
Losses on cash flow hedges.........................................................................
Total income tax expense....................................................................................
Other comprehensive income (loss), net of tax......................................................
Comprehensive income............................................................................................ $
See accompanying notes to financial statements.
(9,657)
6,776
25,275
(10,626)
(7,407)
4,965
8,444
(7,640)
532
24,934
498
11,504
(3,615)
(2,922)
(223)
(6,760)
18,174
(4,261)
(106)
(339)
(4,706)
6,798
116,435
$
103,566
$
5,429
824
(6,574)
8,622
(2,906)
(11,114)
467
(5,252)
(3,286)
2,828
(203)
(661)
(5,913)
76,005
56
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5
EL PASO ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(In thousands)
Cash Flows From Operating Activities:
Net income ......................................................................................................................... $
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service .........................................
Amortization of nuclear fuel ......................................................................................
Deferred income taxes, net ........................................................................................
Allowance for equity funds used during construction ...............................................
Other amortization and accretion ...............................................................................
Gain on sale of property, plant and equipment ..........................................................
Net gains on sale of decommissioning trust funds .....................................................
Other operating activities ..........................................................................................
Change in:
Accounts receivable ...................................................................................................
Inventories .................................................................................................................
Net over-collection (under-collection) of fuel revenues ............................................
Prepayments and other ..............................................................................................
Accounts payable ......................................................................................................
Taxes accrued ............................................................................................................
Other current liabilities ..............................................................................................
Deferred charges and credits .....................................................................................
Net cash provided by operating activities ...................................................
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment .....................................................
Cash additions to nuclear fuel ............................................................................................
Capitalized interest and AFUDC:
Utility property, plant and equipment ........................................................................
Nuclear fuel and other ...............................................................................................
Allowance for equity funds used during construction ...............................................
Decommissioning trust funds:
Purchases, including funding of $3.8 million, $4.5 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 ...................................................................................................................
Payment on maturing RGRT senior notes ..........................................................................
Payment on maturing pollution control bonds ...................................................................
Proceeds from issuance of senior notes .............................................................................
Other financing activities ...................................................................................................
Net cash provided by (used for) financing activities ..................................
Net increase (decrease) in cash and cash equivalents ............................................................
Cash and cash equivalents at beginning of period .................................................................
Years Ended December 31,
2017
2016
2015
98,261
$
96,768
$
81,918
90,843
42,476
49,394
(3,025)
18,954
—
(10,626)
(692)
(138)
(3,073)
17,093
(692)
1,407
1,840
(917)
(12,544)
288,561
84,317
43,748
50,510
(7,023)
17,295
(545)
(7,640)
1,279
(17,511)
265
(14,891)
(1,184)
(2,140)
1,945
2,022
(16,065)
231,150
89,824
43,099
30,846
(10,639)
17,707
(658)
(11,114)
517
4,839
(2,859)
13,344
(3,984)
(11,235)
4,512
3,719
(3,165)
246,671
(190,305)
(38,481)
(225,361)
(42,383)
(281,458)
(41,966)
(6,000)
(5,022)
3,025
(102,920)
97,037
281
(1,559)
(243,944)
(12,006)
(4,990)
7,023
(99,497)
91,268
4,841
5,373
(275,732)
(17,576)
(4,968)
10,639
(110,223)
102,567
721
(470)
(342,734)
(53,337)
(49,603)
(47,059)
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
344,398
(217,192)
(15,000)
—
—
(1,439)
63,708
(32,355)
40,504
8,149
Cash and cash equivalents at end of period ........................................................................... $
6,990
$
8,420
$
See accompanying notes to financial statements.
58
INDEX TO NOTES TO FINANCIAL STATEMENTS
Note A. Summary of Significant Accounting Policies ...........................................................................................................
Note B. New Accounting Standards .......................................................................................................................................
Note C. Regulation .................................................................................................................................................................
Note D. Regulatory Assets and Liabilities..............................................................................................................................
Note E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant..............................................................................
Note F. Accounting for Asset Retirement Obligations ...........................................................................................................
Note G. Common Stock..........................................................................................................................................................
Note H. Accumulated Other Comprehensive Income (Loss) .................................................................................................
Note I. Long-Term Debt and Financing Obligations..............................................................................................................
Note J. Income Taxes..............................................................................................................................................................
Note K. Commitments, Contingencies and Uncertainties ......................................................................................................
Note L. Litigation ...................................................................................................................................................................
Note M. Employee Benefits ...................................................................................................................................................
Page
60
64
66
70
72
75
76
81
83
85
88
90
91
Note N. Franchises and Significant Customers ......................................................................................................................
104
Note O. Financial Instruments and Investments.....................................................................................................................
105
Note P. Supplemental Statements of Cash Flow Disclosures .................................................................................................
110
Note Q. Selected Quarterly Financial Data (Unaudited) ........................................................................................................
111
59
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
A.
Summary of Significant Accounting Policies
General. El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity
in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a full
requirements wholesale customer in Texas.
Basis of Presentation. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed
by the Federal Energy Regulatory Commission (the "FERC").
Use of Estimates. The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles
("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. The Company evaluates its estimates on an on-going basis, including those related to
depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement
obligations ("ARO"). Actual results could differ from those estimates.
Application of the Financial Accounting Standards Board (the "FASB") Guidance for Regulated Operations. Regulated
electric utilities typically prepare their financial statements in accordance with the FASB guidance for regulated operations. The
FASB guidance for regulated operations requires the Company to include an allowance for equity and borrowed funds used during
construction ("AEFUDC" and "ABFUDC") as a cost of construction of electric plant in service. AEFUDC is recognized as income
and ABFUDC is shown as capitalized interest charges in the Company’s statements of operations. The FASB guidance for regulated
operations also requires the Company to show certain recoverable costs as either assets or liabilities on a utility’s balance sheet if
the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already
permitted such cost recovery) or will be credited or refunded to the utility’s customers. The resulting regulatory assets or liabilities
are amortized in subsequent periods based upon the respective amortization periods reflected in a utility’s regulated rates. See Part
II, Item 8, Financial Statements and Supplementary Data, Note D. The Company applies the FASB guidance for regulated operations
for all three of the jurisdictions in which it operates.
Comprehensive Income. Certain gains and losses that are not recognized currently in the statements of operations are reported
as other comprehensive income in accordance with the FASB guidance for reporting comprehensive income.
Utility Plant. Utility plant is generally reported at cost. The cost of renewals and betterments are capitalized and the costs
of repairs and minor replacements are charged to the appropriate operating expense accounts. Depreciation is provided on a straight-
line basis over the estimated remaining lives of the assets (ranging in average from 5 to 48 years). The average composite depreciation
rate utilized in 2017, 2016 and 2015 was 2.27%, 2.28%, and 2.64%, respectively. When property subject to composite depreciation
is retired or otherwise disposed of in the normal course of business, its cost together with the cost of removal, less salvage is
charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed
from the balance sheet accounts and a gain or loss is recognized. During 2016, depreciation and amortization decreased due to
changes in depreciation rates approved by the Public Utility Commission of Texas ("PUCT") in the final order in Docket No.
44941 ("2016 PUCT Final Order") and the New Mexico Public Regulation Commission ("NMPRC") in the final order in Case
No. 15-00127-UT ("NMPRC Final Order") and changes in the estimated life of certain intangible software assets.
The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. The Company is also amortizing its
share of costs associated with on-site spent fuel storage casks at Palo Verde Generating Station ("Palo Verde") over the burn period
of the fuel that will necessitate the use of the storage casks. See Part II, Item 8, Financial Statements and Supplementary Data,
Note E.
Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used
is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be
generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment
charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.
Allowance for Funds Used During Construction ("AFUDC") and Capitalized Interest. The Company capitalizes interest
(ABFUDC) and common equity (AEFUDC) costs to construction work in progress and capitalizes interest to nuclear fuel in
process in accordance with the FERC Uniform System of Accounts as provided for in the FASB guidance. AFUDC is a non-cash
component of income and is calculated monthly and charged to all new eligible construction and capital improvement projects.
60
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
AFUDC is compounded on a semi-annual basis. The average AFUDC rates used in 2017, 2016 and 2015 were 5.38%, 6.43% and
7.18%, respectively.
Asset Retirement Obligation. The FASB guidance sets forth accounting requirements for the recognition and measurement
of liabilities associated with the retirement of tangible long-lived assets. An ARO associated with long-lived assets included within
the scope of the FASB guidance is that for which a legal obligation exists under enacted laws, statutes, written or oral contracts,
including obligations arising under the doctrine of promissory estoppel and legal obligations to perform an asset retirement activity
even if the timing and/or settlement are conditioned on a future event that may or may not be within the control of an entity. See
Part II, Item 8, Financial Statements and Supplementary Data, Note F. Under the FASB guidance, these liabilities are recognized
as incurred if a reasonable estimate of fair value can be established and are capitalized as part of the cost of the related tangible
long-lived assets. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion
expense).
Cash and Cash Equivalents. Temporary cash investments with an original maturity of three months or less are considered
cash equivalents. The Company's cash and cash equivalents do not include amounts held in trust by the nuclear decommissioning
or the pension and other post-retirement benefit trust funds.
Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheet, are reported
at fair value and consist of cash, equity securities and municipal, federal and corporate bonds in trust funds established for
decommissioning of its interest in Palo Verde. Such marketable securities are classified as "available-for-sale" securities and, as
such, unrealized gains and losses are included in accumulated other comprehensive loss as a separate component of common stock
equity. However, if declines in the fair value of marketable securities below original cost basis are determined to be other than
temporary, the declines are reported as losses in the statements of operations and a new cost basis is established for the affected
securities at fair value. Gains and losses are determined using the cost of the security based on the specific identification basis.
See Part II, Item 8, Financial Statements and Supplementary Data, Note O.
Derivative Accounting. Accounting for derivative instruments and hedging activities requires the recognition of derivatives
as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value
of these instruments are recorded in earnings or other comprehensive income. See Part II, Item 8, Financial Statements and
Supplementary Data, Note O.
Inventories. Inventories, primarily parts, materials, supplies, fuel oil and natural gas are stated at average cost, which is not
to exceed recoverable cost.
Operating Revenues Net of Energy Expenses. The Company accrues revenues for services rendered, including unbilled
electric service revenues. Energy expenses are stated at actual cost incurred. The Company’s Texas retail customers are billed
under base rates and a fixed fuel factor approved by the PUCT. The Company’s New Mexico retail customers are billed under
base rates and a fuel adjustment clause which is adjusted monthly, as approved by the NMPRC. The Company's FERC sales for
resale customers are billed under formula base rates and fuel factors and a fuel adjustment clause which is adjusted monthly. The
Company’s recovery of energy expenses is subject to periodic reconciliations of actual energy expenses incurred to actual fuel
revenues collected. The difference between energy expenses incurred and fuel revenues charged to customers is reflected as over/
under-collection of fuel revenues in the balance sheets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.
Revenues. Revenues related to the sale of electricity are generally recorded when service is provided or electricity is delivered
to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic
basis throughout the month. Unbilled revenues are recorded for estimated amounts of energy delivered in the period following
the customers billing cycle to the end of the month. Unbilled revenues are estimated based on monthly generation volumes and
by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included
accrued unbilled revenues of $22.2 million and $21.0 million as of December 31, 2017 and 2016, respectively. The Company
presents revenues net of sales taxes in its statements of operations.
Allowance for Doubtful Accounts. The allowance for doubtful accounts represents the Company’s estimate of existing
accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to
various classes of outstanding receivables. The write-off factors used to estimate uncollectible accounts are based upon
consideration of both historical collections experience and management’s best estimate of future collections success given the
existing collections environment. Additions, deductions and balances for allowance for doubtful accounts for 2017, 2016 and 2015
are as follows (in thousands):
61
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Balance at beginning of year ....................................................................... $
Additions:
Charged to costs and expense...............................................................
Recovery of previous write-offs...........................................................
Uncollectible receivables written off...........................................................
Balance at end of year ................................................................................. $
2017
2016
2015
2,156
$
2,046
$
2,253
3,141
1,122
4,119
2,300
$
2,427
1,395
3,712
2,156
$
2,057
1,613
3,877
2,046
Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting
for income taxes. Deferred income taxes are recognized for the estimated future tax consequences of "temporary differences" by
applying enacted statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial
statement carrying amounts and the tax basis of existing assets and liabilities. Certain temporary differences are accorded flow-
through treatment by the Company's regulators and impact the Company's effective tax rate. The FASB guidance requires that
rate-regulated companies record deferred income taxes for temporary differences accorded flow-through treatment at the direction
of the regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected
in future rates. Because the Company's regulators have consistently permitted the recovery of tax effects previously flowed-through
earnings, the Company has recorded regulatory liabilities and assets offsetting such deferred tax assets and liabilities. During the
third quarter of 2016, the Company changed its accounting for state income taxes from the flow-through method to the normalization
method in accordance with the final orders from the PUCT and the NMPRC in its 2015 rate cases, effective January 1, 2016. See
Part II, Item 8, Financial Statements and Supplementary Data, Note C for further discussion. The effect on deferred tax assets and
liabilities of a change in tax rate is recognized in income in the period that includes the enactment date, unless those deferred taxes
will be returned to customers in which case they are recorded as a regulatory asset or liability. See further discussion in Part II,
Item 8, Financial Statements and Supplementary Data, Note J. The Company recognizes tax assets and liabilities for uncertain tax
positions in accordance with the recognition and measurement criteria of the FASB guidance for uncertainty in income taxes. See
Part II, Item 8, Financial Statements and Supplementary Data, Note J.
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (“TCJA”) was enacted. Substantially all of the provisions of the
TCJA are effective for taxable years beginning after December 31, 2017, with the exception of the discontinuance of bonus
depreciation for regulated public utilities which was effective for assets acquired and placed into service after September 27, 2017.
The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the "IRC"), including amendments
which significantly changed the taxation of business entities and includes specific provisions related to regulated public utilities.
The more significant changes that impact the Company included in the TCJA are reductions in the corporate federal income tax
rate from 35% to 21%, elimination of the corporate alternative minimum tax provisions, additional limitations on deductions of
executive compensation, and limiting the utilization of net operating losses ("NOL") arising after December 31, 2017 to 80% of
taxable income with no carryback but with an indefinite carryforward. The specific provisions related to regulated public utilities
in the TCJA generally provide for the continued deductibility of interest expense, the elimination of bonus depreciation for property
acquired and placed into service after September 27, 2017 and the continuance of rate normalization requirements for accelerated
depreciation benefits and changes to deferred tax balances as a result of the change in corporate federal income tax rate.
The tax effects of changes in tax laws must be recognized in the period in which the law is enacted. GAAP also requires
deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be
realized or settled. Thus, at the date of enactment of the TCJA, the Company’s deferred taxes were re-measured based upon the
new corporate federal income tax rate. The decrease in deferred taxes was recorded as a regulatory liability as it will be subject
to refund to customers and is recorded at the expected cash flow to be reflected in future rates. See Part II, Item 8, Financial
Statements and Supplementary Data, Note J for further discussion.
Earnings per Share. The Company’s restricted stock awards are participating securities and earnings per share must be
calculated using the two-class method in both the basic and diluted earnings per share calculations. For the basic earnings per
share calculation, net income is allocated to the weighted average number of restricted stock awards and to the weighted average
number of shares outstanding. The net income allocated to the weighted average number of shares outstanding is then divided by
the weighted average number of shares outstanding to derive the basic earnings per share. For the diluted earnings per share, net
income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares and
dilutive potential shares outstanding. The Company’s dilutive potential shares outstanding amount is calculated using the treasury
stock method for the unvested performance shares. Net income allocated to the weighted average number of shares and dilutive
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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
potential shares is then divided by the weighted average number of shares and dilutive potential shares outstanding to derive the
diluted earnings per share. See Part II, Item 8, Financial Statements and Supplementary Data, Note G.
Stock-Based Compensation. The Company has a stock-based long-term incentive plan. The Company is required under the
FASB guidance to measure the cost of employee services received in exchange for an award of equity instruments based on the
grant-date fair value of the award. Such costs are recognized over the period during which an employee is required to provide
service in exchange for the award (the "requisite service period") which typically is the vesting period. Compensation cost is not
recognized for anticipated forfeitures prior to vesting of equity instruments. See Part II, Item 8, Financial Statements and
Supplementary Data, Note G.
Pension and Post-retirement Benefit Accounting. See Part II, Item 8, Financial Statements and Supplementary Data, Note
M for a discussion of the Company's accounting policies for its employee benefits.
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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
B.
New Accounting Standards
In March 2016, the FASB issued Accounting Standards Update ("ASU") 2016-09, Compensation - Stock Compensation
(Topic 718) Improvements to Employee Share-Based Payment Accounting to simplify the accounting for share-based payment
transactions, including the income tax consequences, classification of awards either as equity or liabilities, and classification on
the statements of cash flows. The Company adopted the new standard effective January 1, 2017. The adoption of the new standard
did not have a material impact on the Company's financial condition, results of operations or cash flows. The cumulative effect
of the adoption of the new standard was to increase net operating loss carryforward deferred tax assets and retained earnings by
$0.2 million on January 1, 2017.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) to provide a framework
that replaces the existing revenue recognition guidance, and has since modified the standard with several ASUs. The standard
provides that an entity should recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods
or services to customers. More specifically, the standard requires entities to recognize revenue through the application of a five-
step model, which includes the: (i) identification of the contract; (ii) identification of the performance obligations; (iii) determination
of the transaction price; (iv) allocation of the transaction price to the performance obligations; and (v) the recognition of revenue
as the entity satisfies the performance obligations. The Company will adopt the new standard for reporting periods beginning on
January 1, 2018, and intends use the modified retrospective approach.
The Company has analyzed the impact of the new standard on its various revenue and cash flow streams, and the impact on
changes to business processes, systems and controls to support recognition under the new guidance. Tariff sales to customers are
determined to be in the scope of the new standard and represent a significant portion of the Company’s total operating revenues.
The Company has determined that the timing or pattern of revenue recognition from tariff sales will not change. Implementation
of the new standard will also not significantly change the timing or pattern of revenue recognition from other revenue streams.
Upon adoption of the standard, the Company expects its disclosures to disaggregate revenues primarily by tariff based categories
and off-system sales.
In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and
Measurement of Financial Assets and Liabilities to enhance the reporting model for financial instruments by addressing certain
aspects of recognition, measurement, presentation, and disclosure. ASU 2016-01 generally requires entities to measure equity
investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any
changes in fair value in net income. The guidance for classifying and measuring investments in debt securities and loans is not
changed by this ASU, but requires entities to record changes in other comprehensive income. Financial assets and financial liabilities
must be separately presented by measurement category on the balance sheet or in the accompanying notes to the financial statements.
ASU 2016-01 clarifies the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in
combination with the entity's other deferred tax assets. The provisions of this ASU become effective for reporting periods beginning
after December 15, 2017. Upon adoption of the new standard, the Company expects to record the cumulative effects as of January
1, 2018 which will result in a net reduction to accumulated other comprehensive income of $41.0 million, net of tax, and a
corresponding increase in retained earnings for unrealized gains (losses) related to equity securities owned by the Company.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among
organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring qualitative and quantitative
disclosures on leasing agreements. ASU 2016-02 maintains a distinction between finance leases and operating leases similar to
the distinction under previous leases guidance for capital leases and operating leases. The impact of leases reported in the Company's
operating results and statement of cash flows are expected to be similar to previous GAAP. ASU 2016-02 requires the recognition
in the statement of financial position, by the lessee, of a liability to make lease payments (the lease liability) and a right-of-use
asset representing its right to use the underlying asset for the lease term. How leases are recorded in regard to financial position
represents a significant change from previous GAAP guidance. The lessee is permitted to make an accounting policy election to
not recognize lease assets and lease liabilities for short-term leases. Implementation of the standard will be required for reporting
periods beginning after December 15, 2018. Adoption of the new lease accounting standard will require the Company to apply
the new standard to the earliest period using a modified retrospective approach. The Company is currently in the process of
evaluating the impact of the new standard, which includes continuing to monitor activities of the FASB, including the impact of
the recently issued ASU 2018-01, and the proposed project to allow entities to adopt the standard with a cumulative effect adjustment
as of the beginning of the adoption year, while maintaining prior year comparative financial information and disclosures as reported.
ASU 2018-01, Land Easement Practical expedient for Transition to Topic 842, provides an optional practical expedient to not
evaluate existing or expired land easements under Topic 842, if those land easements were not previously accounted for as leases
under Accounting Standards Codification ("ASC") Topic 840. The Company currently anticipates that it will apply the practical
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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
expedient under ASU 2018-01 to its existing or expired land easements as part of its transition to Topic 842. The Company's
evaluation process also includes evaluating the impact, if any, on changes to business processes, systems and controls to support
recognition and disclosure under the new guidance; however, at this time the Company is unable to determine the impact this
standard will have on the financial statements and related disclosures.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326). ASU 2016-13 changes how
companies measure and recognize credit impairment for many financial assets. The new current expected credit loss model will
require companies to immediately recognize an estimate of credit losses expected to occur over the remaining life of the financial
assets that are in the scope of the standard. The ASU also makes targeted amendments to the current impairment model for available-
for-sale debt securities. The provisions of ASU 2016-13 will be required for reporting periods beginning after December 15, 2019.
ASU 2016-13 will be applied in a modified retrospective approach through a cumulative-effect adjustment to retained earnings
as of the beginning of the first reporting period in which the guidance is implemented. The Company is currently assessing the
future impact of ASU 2016-13.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts
and Cash Payments to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement
of cash flows. The provisions of ASU 2016-15 will be required for reporting periods beginning after December 15, 2017. ASU
2016-15 will be applied using a retrospective transition method to each period presented. If it is impracticable to apply ASU
2016-15 retrospectively for some of the issues, the amendments for those issues may be applied prospectively as of the earliest
date practicable. The Company is currently assessing the future impact of this ASU.
In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits (Topic 715) Improving the Presentation
of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. ASU 2017-07 amends Accounting Standards
Codification 715, Compensation - Retirement Benefits, to require companies to present the service cost component of net benefit
cost in the income statement line items where compensation cost is reported. Companies will present all other components of net
benefit cost separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In
addition, only the service cost component will be eligible for capitalization in assets. The amendments in ASU 2017-07 will be
required for reporting periods beginning after December 15, 2017. The amendments in ASU 2017-07 should be applied
retrospectively for the income statement presentation of the service cost component and the other components of net benefit costs
and prospectively, on and after the effective date, for the capitalization of the service cost component. The Company expects that
the retrospective impact of implementing this ASU on the Statement of Operations for the twelve months ended December 31,
2017 would be an increase in (i) Other operations of $8.2 million, (ii) Other interest of $15.8 million, (iii) Miscellaneous non-
operating income of $32.4 million, and (iv) Miscellaneous non-operating deductions of $8.4 million.
In May 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718), Scope of Modification
Accounting, to provide guidance about when to account for a change to the terms or conditions of a share-based payment award
as a modification. Under ASU 2017-09, modification accounting is required only if the fair value, the vesting conditions, or the
classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The amendments of
ASU 2017-09 will be required for reporting periods beginning after December 15, 2017. ASU 2017-09 should be applied
prospectively to an award modified on or after the adoption date. The Company is assessing the future impact of ASU 2017-09;
however, it currently does not expect the impact of this ASU to be significant to the Company's financial conditions, results of
operations or cash flows.
In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220) as a
result of concerns raised by stakeholders due to the TCJA. More specifically, the concerns raised are that because the adjustment
due to the reduction of the historical corporate income tax rate of 35% to the newly enacted corporate income tax rate of 21% is
required to be made for accumulated deferred income taxes, the tax effect of items within accumulated other comprehensive
income (“AOCI”) do not reflect the appropriate tax rate under current accounting standards which would result in "stranded taxes".
ASU 2018-02 allows companies to reclassify stranded taxes from AOCI to retained earnings. The amount of the reclassification
would be the difference between the historical corporate income tax rate of 35% and the newly enacted 21% corporate income
tax rate. The provisions of ASU 2018-02 are effective for fiscal years and interim periods within that reporting period beginning
after December 15, 2018. Early adoption is permitted, including adoption in any interim periods for reporting periods for which
financial statements have not been issued. The Company is currently in the process of evaluating the impact of ASU 2018-02 and
its impact on regulated utilities. At December 31, 2017, the Company has $7.2 million in stranded taxes in AOCI.
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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
C.
Regulation
General
The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC and
the FERC. Municipal orders, ordinances and other agreements regarding rates and services adopted by Texas municipalities are
subject to review and approval by the PUCT. The FERC has jurisdiction over the Company's wholesale (sales for resale) transactions,
transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and
the FERC are subject to judicial review.
Texas Regulatory Matters
2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities
incorporated in its Texas service territory, and the PUCT in Docket No. 44941, a request for an annual increase in non-fuel base
revenues ("2015 Texas Retail Rate Case").
On July 21, 2016, the parties to PUCT Docket No. 44941 filed the Joint Motion to Implement Uncontested Amended and
Restated Stipulation and Agreement which was unopposed by the parties (the "2016 Unopposed Settlement"). On August 25, 2016,
the PUCT approved the 2016 Unopposed Settlement and issued the 2016 PUCT Final Order, as proposed. The 2016 PUCT Final
Order provided for: (i) an annual non-fuel base rate increase, lower annual depreciation expense, a revised return on equity for
AFUDC purposes, and the inclusion of substantially all new plant in service in rate base; (ii) an additional annual non-fuel base
rate increase of $3.7 million related to Four Corners Generating Station ("Four Corners") costs, which was collected through a
surcharge that terminated on July 11, 2017; (iii) removing the separate rate treatment for residential customers with solar systems
that the Company had proposed in its August 10, 2015 filing; (iv) allowing the Company to recover $3.1 million in rate case
expenses through a separate surcharge; and (v) allowing the Company to recover revenues associated with the relate back of rates
to consumption on and after January 12, 2016 through March 31, 2016 through a separate surcharge.
Interim rates associated with the annual non-fuel base rate increase became effective on April 1, 2016. The additional
surcharges associated with the incremental Four Corners costs, rate case expenses and the relate back of rates to consumption on
and after January 12, 2016 through March 31, 2016 were implemented on October 1, 2016.
For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail
Rate Case until it received the 2016 PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016
the cumulative effect of the 2016 PUCT Final Order, which related back to January 12, 2016.
2017 Texas Retail Rate Case Filing. On February 13, 2017, the Company filed with the City of El Paso, other municipalities
incorporated in the Company's Texas service territory and the PUCT in Docket No. 46831, a request for an increase in non-fuel
base revenues ("2017 Texas Retail Rate Case"). On November 2, 2017, the Company filed the Joint Motion to Implement
Uncontested Stipulation and Agreement with the Administrative Law Judges for the 2017 Texas Retail Rate Case.
On December 18, 2017, the PUCT issued its final order in the Company's rate case pending in Docket No. 46831 ("2017
PUCT Final Order"), which provides, among other things, for the following: (i) an annual non-fuel base rate increase of $14.5
million; (ii) a return on equity of 9.65%; (iii) all new plant in service as filed in the Company's rate filing package was prudent
and used and useful and therefore is included in rate base; (iv) recovery of the costs of decommissioning Four Corners in the
amount of $5.5 million over a seven year period beginning August 1, 2017; (v) the Company to recover reasonable rate case
expenses of approximately $3.4 million through a separate surcharge over a three year period; and (vi) a requirement that the
Company file a refund tariff if the federal statutory income tax rate, as it relates to the Company, is decreased before the Company
files its next rate case. The 2017 PUCT Final Order also establishes baseline revenue requirements for recovery of future transmission
and distribution investment costs, and includes a minimum monthly bill of $30.00 for new residential customers with distributed
generation, such as private rooftop solar. Additionally, the 2017 PUCT Final Order allows for the annual recovery of $2.1 million
of nuclear decommissioning funding and establishes annual depreciation expense that is approximately $1.9 million lower than
the annual amount requested by the Company in its initial filing. Finally, the 2017 PUCT Final Order allows for the Company to
recover revenues associated with the relate back of rates to consumption on and after July 18, 2017 through a separate surcharge.
New base rates, including additional surcharges associated with rate case expenses and the relate back of rates to consumption
on and after July 18, 2017 through December 31, 2017 were implemented in January 2018.
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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
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 requires the Company to file a refund tariff if the federal statutory income tax rate, as it relates
to the Company, is decreased before the Company files its next rate case. Following the enactment of the TCJA on December 22,
2017, and in compliance with the 2017 PUCT Final Order, the Company will reduce the recognition of Texas jurisdictional revenues
beginning January 1, 2018, to approximate the tax savings resulting from the TCJA and will file a refund tariff which the Company
will ask to be implemented in the first half of 2018. The refund tariff is expected to be reflected in rates over a period of a year
and will be updated annually until new base rates are implemented pursuant to the Company's next rate case filing. See Part II,
Item 8, Financial Statements and Supplementary Data, Note J for further details.
Energy Efficiency Cost Recovery Factor. On May 1, 2017, the Company filed its annual application, which was assigned
PUCT Docket No. 47125, to establish its energy efficiency cost recovery factor ("EECRF") for 2018. In addition to projected
energy efficiency costs for 2018 and a true-up to prior year actual costs, the Company requested approval of an incentive bonus
for the 2016 energy efficiency program results in accordance with PUCT rules. Interim rates were approved effective January 1,
2018. The Company, the staff of the PUCT, and the City of El Paso reached an agreement that includes an incentive bonus of $0.8
million. The agreement was filed on January 25, 2018, and was approved by the PUCT on February 15, 2018.
Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered
from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows
the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon
the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires
the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount
and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to
surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery
to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the
previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT
in fuel reconciliation proceedings.
On November 30, 2016, the Company filed a request, which was assigned PUCT Docket No. 46610, to increase its fixed
fuel factor by approximately 28.8% to reflect increased fuel expenses primarily related to an increase in the price of natural gas
used to generate power. The increase in the fixed fuel factor was effective on an interim basis January 1, 2017 and approved by
the PUCT on January 10, 2017. As of September 30, 2017, the Company had over-recovered fuel costs in the amount of $1.1
million for the Texas jurisdiction. On October 13, 2017, the Company filed a request, which was assigned PUCT Docket No.
47692, to decrease the Texas fixed fuel factor by approximately 19% to reflect decreased fuel expenses primarily related to a
decrease in the price of natural gas used to generate power. The decrease in the Texas fixed fuel factor became effective beginning
with the November 2017 billing month and will continue thereafter until changed by the PUCT. At December 31, 2017, the
Company had a net fuel over-recovery balance of approximately $5.8 million in Texas.
Fuel Reconciliation Proceeding. On September 27, 2016, the Company filed an application with the PUCT, designated as
PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of
April 1, 2013 through March 31, 2016. On June 29, 2017, the PUCT approved a settlement in this proceeding. The settlement
provides for the reconciliation of fuel and purchased power costs incurred from April 1, 2013 through March 31, 2016. Additionally,
the settlement modifies and tightens the Palo Verde performance rewards measurement bands beginning with the 2018 performance
period. The financial results for the twelve months ended December 31, 2017 include a $5.0 million, pre-tax increase to income
reflecting the settlement of the Texas fuel reconciliation proceeding. This amount represents Palo Verde performance rewards
associated with the 2013 to 2015 performance periods net of disallowed fuel and purchased power costs as approved in the
settlement. Texas jurisdictional fuel and purchased power costs subject to prudence review are costs from April 1, 2016 through
December 31, 2017 that total approximately $250.9 million.
Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program that
includes the construction and ownership of a 3 MW solar photovoltaic system located at the Company's Montana Power Station
("MPS"). Participation is on a voluntary basis, and customers contract for a set capacity (kW) amount and receive all energy
produced. This case was assigned PUCT Docket No. 44800. The Company filed a settlement agreement among all parties on July
1, 2016 approving the program, and the PUCT approved the settlement agreement and program on September 1, 2016. On April 19,
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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
2017, the Company announced that the entire 3 MW program was fully subscribed by approximately 1,500 Texas customers. The
Community Solar facility began commercial operation on May 31, 2017.
Four Corners Generating Station. On February 17, 2015, the Company and Arizona Public Service Company ("APS") entered
into an asset purchase agreement (the "Purchase and Sale Agreement") providing for the sale of the Company's interest in Four
Corners to APS. The sale of the Company's interest in Four Corners closed on July 6, 2016. See Part II, Item 8, Financial Statements
and Supplementary Data, Note E for further details on the sale of Four Corners.
On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and
certain rate and accounting findings related to the Purchase and Sale Agreement. This case was assigned PUCT Docket No. 44805.
Subsequent to the filing of the application, the case was subject to numerous procedural matters, including a March 23, 2016 order
in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the
requested rate and accounting findings, including coal mine reclamation costs, in a rate case proceeding. On September 1, 2016,
a motion by parties in the proceeding to suspend the procedural schedule in order to pursue settlement was approved. On March 3,
2017, the Company filed a Joint Motion to Implement Stipulation and Agreement (the "Stipulation and Agreement"), and PUCT
Staff filed its recommendation that the Company’s disposition of its interest in Four Corners was reasonable and consistent with
the public interest. Additionally, the signatories of the Stipulation and Agreement agreed to support the recovery of the Company's
Four Corners decommissioning costs in the 2017 Texas Retail Rate Case. A final order approving the Stipulation and Agreement
was adopted by the PUCT on March 30, 2017. The approval to recover Four Corners decommissioning costs was included in the
2017 PUCT Final Order.
Other Required Approvals. The Company has obtained other required approvals for tariffs and other approvals required by
the Texas Public Utility Regulatory Act and the PUCT.
New Mexico Regulatory Matters
2015 New Mexico Rate Case Filing. On May 11, 2015, the Company filed a request with the NMPRC, in Case No. 15-00127-
UT, for an annual increase in non-fuel base rates. On June 8, 2016, the NMPRC issued the NMPRC Final Order which approved
an annual increase in non-fuel base rates of approximately $0.6 million, an increase of approximately $0.5 million in other service
fees and a decrease in the Company's allowed return on equity to 9.48%. The NMPRC Final Order concluded that all of the
Company's new plant in service was reasonable and necessary and therefore would be recoverable in rates. The Company's rates
were approved by the NMPRC effective July 1, 2016 and implemented at such time.
Future New Mexico Rate Case Filing. NMPRC Case No. 15-00109-UT required the Company to make a rate filing in
New Mexico in the second quarter of 2017 using a historical test year ended December 31, 2016. On March 24, 2017, the Company,
NMPRC Utility Division Staff and the New Mexico Attorney General filed a Joint Motion to Modify Filing Date Stated in Final
Order requesting that the rate filing date be changed to no later than July 31, 2019, using the appropriate historical test year period.
The joint request was approved by the NMPRC on April 12, 2017. The NMPRC has initiated an investigation into the impact of
the TCJA on utility customers that may require earlier action by the Company. The Company is evaluating possible approaches
to begin providing a refund credit for the TCJA income tax rate decrease to New Mexico customers.
Fuel and Purchased Power Costs.Historically, fuel and purchased power costs were recovered through base rates and a Fuel
and Purchased Power Cost Adjustment Clause (the "FPPCAC") that accounts for changes in the costs of fuel relative to the amount
included in base rates. Effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs
are no longer recovered through base rates but are recovered through the FPPCAC. The Company's request to reconcile its fuel
and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in Case No. 15-00127-UT.
New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2017 that total
approximately $173.1 million. At December 31, 2017, the Company had a net fuel over-recovery balance of approximately $0.4
million in New Mexico. As required, the Company filed a request to continue use of its FPPCAC with the NMPRC on January 5,
2018 which was assigned NMPRC Case No. 18-00006-UT.
5 MW Holloman Air Force Base ("HAFB") Facility Certificate of Convenience and Necessity ("CCN"). On October 7, 2015,
in NMPRC Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a 5 MW solar power generation facility
located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a retail contract, which
includes a power sales agreement for the facility, to replace the existing load retention agreement which was approved by final
order issued October 5, 2016 in NMPRC Case No. 16-00224-UT. Construction of the solar generation facility is expected to be
completed in the third quarter of 2018.
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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
New Mexico Efficient Use of Energy Recovery Factor. On July 1, 2016, the Company filed its annual application requesting
approval of its 2017 Energy Efficiency and Load Management Plan and to establish energy efficiency cost recovery factors for
2017. In addition to projected energy efficiency costs for 2017, the Company requested approval of a $0.4 million incentive for
2017 energy efficiency programs in accordance with NMPRC rules. This case was assigned Case No. 16-00185-UT. On
February 22, 2017, the NMPRC issued a Final Order approving the Company’s 2017 Energy Efficiency and Load Management
Plan and authorizing recovery in 2017 of a base incentive of $0.4 million. The Company’s energy efficiency cost recovery factors
were approved and effective in customer bills beginning on March 1, 2017.
On July 1, 2016, the Company filed its 2015 Annual Report for Energy Efficiency Programs, which included an incentive
for verified 2015 program performance of $0.3 million, which was approved in Case No. 13-00176-UT. The Company recorded
the $0.3 million approved incentive in operating revenues in the first quarter of 2017. In addition, on June 30, 2017, the Company
filed its 2016 Annual Report for Energy Efficiency Programs, which included an incentive for verified 2016 program performance
of $0.4 million that was approved in Case No. 13-00176-UT. The Company recorded the $0.4 million approved incentive in
operating revenues in the third quarter of 2017.
Revolving Credit Facility, Issuance of Long-Term Debt, and Securities Financing. On October 7, 2015, the Company received
approval in NMPRC Case No. 15-00280-UT to guarantee the issuance of up to $65.0 million of long-term debt by the Rio Grande
Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations, which
remains effective. On October 4, 2017, the Company received additional approval in NMPRC Case No. 17-00217-UT to amend
and extend its Revolving Credit Facility ("RCF"), issue up to $350.0 million in long-term debt and to redeem and refinance the
$63.5 million 2009 Series A 7.25% Pollution Control Bonds and the $37.1 million 2009 Series B 7.25% Pollution Control Bonds,
which have optional redemptions beginning in 2019. The NMPRC approval to issue $350.0 million in long-term debt supersedes
its prior approval.
Other Required Approvals. The Company has obtained other required approvals for tariffs and other approvals as required
by the New Mexico Public Utility Act and the NMPRC.
Federal Regulatory Matters
Revolving Credit Facility; Issuance of Long-Term Debt, Securities Financing, and Guarantee of Debt. On October 31, 2017,
the FERC issued an order in Docket No. ES17-54-000 approving the Company’s filing to (i) amend and extend the RCF; (ii) issue
up to $350.0 million in long-term debt; (iii) guarantee the issuance of up to $65.0 million of long-term debt by the RGRT; and (iv)
redeem and refinance the $63.5 million 2009 Series A 7.25% Pollution Control Bonds and the $37.1 million 2009 Series B 7.25%
Pollution Control Bonds, which have optional redemptions beginning in 2019. The order also approves the Company's request to
continue to utilize the Company's existing RCF with the ability to amend and extend at a future date. The authorization is effective
from November 15, 2017 through November 14, 2019 and supersedes prior FERC approvals.
Other Required Approvals. The Company has obtained required approvals for rates, tariffs and other approvals as required
by the FERC.
United States Department of Energy ("DOE"). The DOE regulates the Company's exports of power to Mexico pursuant to
a DOE grant of export authorization. In addition, the Company is the holder of two presidential permits issued by the DOE under
which the Company constructed and operates border facilities crossing the United States/Mexico border.
The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's
uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Part II, Item 8, Financial Statements
and Supplementary Data, Note E for discussion of spent fuel storage and disposal costs.
Sales for Resale and Network Transmission Service to Rio Grande Electric Cooperative
The Company provides firm capacity and associated energy to the Rio Grande Electric Cooperative ("RGEC") pursuant to
an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission
service to the RGEC pursuant to the Company's Open Access Transmission Tariff ("OATT"). The contract includes a formula-
based rate that is updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible
fuel and purchased power costs allocable to the RGEC. The Company's service to RGEC is regulated by FERC.
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EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
D.
Regulatory Assets and Liabilities
The Company's operations are regulated by the PUCT, the NMPRC and the FERC. Regulatory assets represent probable
future recovery of previously incurred costs, which will be collected from customers through the ratemaking process. Regulatory
liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through
the ratemaking process. Regulatory assets and liabilities reflected in the Company's balance sheet are presented below (in
thousands):
Amortization
Period Ends
December 31,
2017
December 31,
2016
Regulatory assets
Regulatory tax assets ..............................................................
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) ..............................................
Texas demand response program ...........................................
Texas military base discount and recovery factor ..................
New Mexico renewable energy credits and related costs (j)..
New Mexico 2010 FPPCAC audit .........................................
New Mexico Palo Verde deferred depreciation......................
New Mexico 2015 rate case costs ..........................................
New Mexico 2017 rate case costs ..........................................
New Mexico demand response program ................................
(a)
May 2035
(c)(d)
(e)
(d)
August 2042
January 2021
January 2021
January 2019
(h)
(i)
June 2022
June 2019
(k)
June 2019
(l)
Total regulatory assets
Regulatory liabilities
Regulatory tax liabilities ........................................................
Accumulated deferred investment tax credit..........................
Texas energy efficiency..........................................................
New Mexico energy efficiency ..............................................
Texas military base discount and recovery factor ..................
New Mexico gain on sale of assets (p)...................................
(m)
(n)
(o)
(o)
(i)
June 2019
Total regulatory liabilities
$
$
$
$
40,512
14,926
4,726
6,604
3,536
761
1,144
3,642
8,591
133
213
5,823
326
4,263
644
—
192
96,036
289,013
4,816
895
1,394
—
567
296,685
$
$
$
$
66,670
15,780
8,181
1,400
3,831
794
2,670
246
6,455
—
—
6,937
398
4,415
1,074
10
—
118,861
10,648
3,328
1,288
2,159
184
828
18,435
______________________________
(a) This item relates to (i) the regulatory treatment of the equity portion of AFUDC which is recovered in rate base by an offset
with the related accumulated deferred income tax liability, and (ii) excess deferred state income taxes which are recovered
through amortization to tax expense in cost of service. The amortization period for the excess deferred state income taxes is
15 years as established in the 2016 PUCT Final Order and the NMPRC Final Order.
(b) This item is recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance.
(c) This item relates to coal reclamation costs associated with Four Corners. The Texas portion was approved for recovery in
the 2016 Texas Fuel Reconciliation and will be recovered over seven years through June 2023. The New Mexico amortization
period is anticipated to be established in the next general rate case.
(d) This item is recovered through fuel recovery mechanisms established by tariffs.
(e) This item relates to the decommissioning of Four Corners. The Texas portion was approved for recovery in the 2017 PUCT
Final Order and will be recovered over seven years through July 2024. The New Mexico amortization period is anticipated
to be established in the next general rate case.
The 2017 PUCT Final Order approved a new recovery period for these costs, beginning January 10, 2018.
(f)
70
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
(g) This item relates to the recovery of revenues through two separate surcharges; one for the 2015 Texas Retail Rate Case relate
back revenues beginning October 1, 2016 and ending September 30, 2017, and a second surcharge for the 2017 Texas Retail
Rate Case relate back revenues beginning January 10, 2018 and ending January 9, 2019. See Part II, Item 8, Financial
Statements and Supplementary Data, Note C.
(h) Recovery of this item will be addressed in the next EECRF filing.
(i)
This item represents the net asset/net liability related to the military discount which is recovered from non-military customers
through a recovery factor that is set annually.
This item relates to renewable energy credits and procurement plan costs, of which a component has been approved for
recovery in the NMPRC Final Order. The remaining balance will be requested for recovery in the next general rate case.
(j)
(k) The amortization period for this item is based upon the Nuclear Regulatory Commission license life for each unit at Palo
Verde.
(l) Amortization period is anticipated to be established in next general rate case.
(m) This item primarily relates to the reduction in the federal corporate income tax rate from 35% to 21% as enacted by the TCJA.
The amortization period for the recovery on this item will be addressed in the next base rate filings in all jurisdictions. See
Part II, Item 8, Financial Statements and Supplementary Data, Note J for further details.
(n) The amortization period is based upon the life of the associated assets.
(o) This item is recovered or credited through a recovery factor that is set annually.
(p) This item relates to the gains on the sales of assets the Company shares with its New Mexico customers over a three year
period.
71
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
E.
Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant
The table below presents the balance of each major class of depreciable assets at December 31, 2017 (in thousands):
Nuclear production ....................................................................... $
Steam and other ............................................................................
Total production ....................................................................
Transmission ................................................................................
Distribution...................................................................................
General .........................................................................................
Intangible......................................................................................
Gross
Plant
994,075
952,672
1,946,747
520,126
1,183,289
226,325
105,608
Total....................................................................................... $ 3,982,095
$
Accumulated
Depreciation
Net
Plant
655,376
738,121
1,393,497
255,646
808,851
159,978
43,948
$ (1,320,175) $ 2,661,920
(338,699) $
(214,551)
(553,250)
(264,480)
(374,438)
(66,347)
(61,660)
The Company owns a 15.8% interest in each of the three nuclear generating units and common facilities at Palo Verde, in
Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison
Company ("SCE"), PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power
District ("SRP") and the Los Angeles Department of Water and Power.
A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2017
and 2016 is as follows (in thousands):
Electric plant in service ............................................................... $
Accumulated depreciation ...........................................................
Construction work in progress.....................................................
Total...................................................................................... $
994,075
(338,699)
40,946
696,322
$
$
97,603
(72,822)
1,014
25,795
$
$
948,382
(320,000)
50,598
678,980
$
$
97,652
(74,408)
1,895
25,139
December 31, 2017
December 31, 2016
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):
2015 ..................................................................................... $
2016 .....................................................................................
2017 .....................................................................................
2018 (estimated) ..................................................................
2019 (estimated) ..................................................................
2020 (estimated) ..................................................................
2021 (estimated) ..................................................................
2022 (estimated) ..................................................................
6,482
5,302
6,409
6,835
6,485
6,048
5,128
4,328
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 (the "ANPP Participation Agreement"). APS serves as operating agent for Palo Verde,
and under the ANPP Participation Agreement, the Company has limited ability to influence operations and costs at Palo Verde.
Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitlements in the same
proportion as their percentage interests in the generating units, and each participant is required to fund its share of fuel, other
operations, maintenance and capital costs. The Company’s share of direct expenses in Palo Verde and other jointly-owned utility
plants is reflected in fuel expense, other operations expense, maintenance expense, miscellaneous other deductions, and taxes
other than income taxes in the Company’s statements of operations. The ANPP Participation Agreement provides that if a participant
fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by
the defaulting participant. Because it is impracticable to predict defaulting participants, the Company cannot estimate the maximum
potential amount of future payment, if any, which could be required under this provision.
Nuclear Regulatory Commission. The Nuclear Regulatory Commission ("NRC") regulates the operation of all commercial
nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities
and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee’s safety performance.
Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the NRC.
The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and
issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to
June 2045, April 2046 and November 2047, respectively.
Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company funds its share of the
estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective
operating licenses and is required to maintain a minimum accumulation and funding level in its decommissioning account at the
end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent
trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded.
At December 31, 2017, the Company’s decommissioning trust fund had a balance of $286.9 million, which is above its minimum
funding level. The Company monitors the status of its decommissioning funds and adjusts deposits, if necessary.
Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers
retained by APS. In April 2017, the Palo Verde Participants approved the 2016 Palo Verde decommissioning study (“2016 Study”).
The 2016 Study estimated that the Company must fund approximately $432.8 million (stated in 2016 dollars) to cover its share
of decommissioning costs which was an increase in decommissioning costs of $52.1 million (stated in 2016 dollars) from the 2013
Palo Verde decommissioning study. The effect of this change increased the ARO by $3.5 million, which was recorded during the
second quarter of 2017, and increased annual expenses starting in April 2017. Although the 2016 Study was based on the latest
available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory
requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of
years, estimates of the cost to dispose of low-level radioactive waste are subject to uncertainty. As provided in the ANPP Participation
Agreement, the participants are required to conduct a new decommissioning study every three years. While the Company attempts
to seek amounts in rates to meet its decommissioning obligations, it is not able to conclude given the evidence available to it now
that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. The Company
is ultimately responsible for these costs and its future actions combined with future decisions from regulators will determine how
successful the Company is in this effort.
Spent Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the
DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all
domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or
High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent
nuclear fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach
of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to accept Palo
Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On August 18, 2014, APS and the
DOE entered into a settlement agreement stipulating to a dismissal of the lawsuit. Pursuant to the terms of the August 18, 2014
settlement agreement, APS files annual claims for the period July 1 of the then-previous year to June 30 of the then-current year.
The settlement agreement, as amended, provides APS with a method for submitting claims and receiving recovery for costs incurred
through December 31, 2016, which has been extended to December 31, 2019. The Company's share of costs recovered are presented
73
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
below (in thousands):
Amount Credited
to Customers
through Fuel
Period Credited
Costs Recovery Period
Amount Refunded
Adjustment Clauses
to Customers
January 2007 - June 2011
$
July 2011 - June 2014
July 2014 - June 2015
July 2015 - June 2016
$
9,076
6,643
1,884
1,779
7,944
5,759
1,581
1,432
September 2014
March 2015
March 2016
March 2017
On October 31, 2017, APS filed an $8.9 million claim for the period July 1, 2016 through June 30, 2017. The Company's
share of this claim is approximately $1.4 million. In February 2018, the DOE approved this claim. Any reimbursement is anticipated
to be received in the first half of 2018, and the majority of the reimbursement received by the Company is expected to be credited
to customers through the applicable fuel adjustment clauses.
DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations
by designing, licensing, constructing and operating a permanent geologic repository in Yucca Mountain, Nevada. In March 2010,
the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending
before the NRC. Several interested parties have intervened in the NRC proceeding. The Company cannot predict when spent fuel
shipments to the DOE will commence.
Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear
fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has
sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation,
which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel
are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to
accommodate all of the fuel that will be irradiated during the period of extended operation.
Liability and Insurance Matters. The Palo Verde Participants have insurance for public liability resulting from nuclear energy
hazards to the full limit of liability under federal law, which is currently at $13.4 billion. This potential liability is covered by
primary liability insurance provided by commercial insurance carriers in the amount of $450.0 million, and the balance is covered
by an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the
accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per
incident basis. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately
$127.3 million, subject to an annual limit of $19.0 million. Based upon the Company's 15.8% interest in the three Palo Verde
units, the Company's maximum potential assessment per incident for all three units is approximately $60.4 million, with an annual
payment limitation of approximately $9.0 million.
The Palo Verde Participants maintain $2.75 billion of "all risk" nuclear property insurance. The insurance provides coverage
for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by
a release of radioactive material, the policy's coverage limit is $2.25 billion. The Company has also secured insurance against
portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen
outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy
conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies.
If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance
programs, the Company could be assessed retrospective premium adjustments of up to $13.0 million for the current policy period.
Palo Verde Operations and Maintenance Expense. Included in other operations and maintenance expenses are expenses
associated with Palo Verde as follows (in thousands):
Years Ended December 31,
2017
$
99,364
$
2015
96,914
$
97,639
2016
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 C for a discussion of regulatory filings associated
with Four Corners.
F.
Accounting for Asset Retirement Obligation
The Company records its ARO in accordance with the FASB guidance. This guidance affects the accounting for the
decommissioning of Palo Verde and the method used to report the decommissioning obligation. The Company also complies with
the FASB guidance for conditional ARO which primarily affects the accounting for the disposal obligations of the Company’s
fuel oil storage tanks, water wells, evaporative ponds and asbestos found at the Company’s gas-fired generating plants. The
Company’s ARO are subject to various assumptions and determinations such as: (i) whether a legal obligation exists to remove
assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in
decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities.
Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future
as an expense for ARO. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion
expense). If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation
to do so, it will record such retirement costs as incurred.
The ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2016 Palo Verde
decommissioning study. See Part II, Item 8, Financial Statements and Supplementary Data, Note E. The ARO liability is calculated
by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The
resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate.
As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost
estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume responsibility
for the permanent disposal of spent fuel, such costs have not been included in the ARO calculation. The Company maintains six
external trust funds with an independent trustee that are legally restricted to settling its ARO at Palo Verde. The fair value of the
funds at December 31, 2017 is $286.9 million.
The FASB guidance requires the Company to revise its previously recorded ARO for any changes in estimated cash flows
including changes in estimated probabilities related to timing of settlements. Any changes that result in an upward revision to
estimated cash flows shall be treated as a new liability. Any downward revisions to the estimated cash flows result in a reduction
to the previously recorded ARO. The 2013 Study resulted in a downward revision of $1.9 million. In the second quarter of 2017,
the Company implemented the results of the 2016 Palo Verde decommissioning study and revised its ARO related to Palo Verde
to increase its estimated cash flows from the 2013 Study to the 2016 Study. See Part II, Item 8, Financial Statements and
Supplementary Data, Note E. The assumptions used to calculate the increases to the Palo Verde ARO liability are as follows:
Escalation
Rate
Credit-Risk
Adjusted
Discount Rate
Original ARO liability.........................
Incremental ARO liability (2010) .......
Incremental ARO liability (2016) .......
3.60%
3.60%
3.25%
9.50%
6.20%
4.34%
An analysis of the activity of the Company’s total ARO liability from January 1, 2015 through December 31, 2017, including
the effects of each year’s estimate revisions, is presented below (in thousands). In 2017, the estimate revision reflects increases
in the estimated cash flows related to Palo Verde's decommissioning due to implementing the 2016 Palo Verde decommissioning
study. In 2016, the settled liabilities reflect the sale of the Company's interest in Four Corners including the related ARO.
75
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
ARO liability at beginning of year........................ $
Liabilities incurred .........................................
Liabilities settled............................................
Revisions to estimate .....................................
Accretion expense..........................................
ARO liability at end of year .................................. $
2017
81,800
138
(19)
3,461
7,649
93,029
$
$
2016
81,621
—
(6,993)
—
7,172
81,800
$
$
2015
74,577
189
—
—
6,855
81,621
The Company has transmission and distribution lines which are operated under various land rights agreements. Upon the
expiration of any non-perpetual land rights agreement, the Company may have a legal obligation to remove the lines; however,
the Company has assessed the likelihood of this occurring as remote. The majority of these agreements are perpetual or include
renewal options which the Company routinely exercises. The amount of cost of removal collected in rates for non-legal liabilities
has not been material.
G.
Common Stock
Overview
The Company’s common stock has a stated value of $1 per share, with no cumulative voting rights or preemptive rights.
Holders of the common stock have the right to elect the Company’s directors and to vote on other matters.
Long-Term Incentive Plan
On May 29, 2014, the Company’s shareholders approved an amended and restated stock-based long-term incentive plan (the
"Amended and Restated 2007 LTIP") and authorized the issuance of up to 1.7 million shares of the Company's common stock for
the benefit of directors and employees. Under the Amended and Restated 2007 LTIP, shares of the Company's common stock may
be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted
stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares,
purchase shares on the open market, or issue shares from shares of the Company's common stock the Company has repurchased
to meet the share requirements of the Amended and Restated 2007 LTIP. Beginning in 2015, shares of the Company's common
stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury
stock. As discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note A, the Company accounts for its stock-
based long-term incentive plan under the FASB guidance for stock-based compensation.
Restricted Stock with Service Condition and Other Stock-Based Awards. The Company has awarded restricted stock and
other stock-based awards under its long-term incentive plan. Restrictions from resale on restricted stock awards generally lapse
and awards vest over periods of one to three years, subject to continuous service requirements. The market value of the unvested
restricted stock at the date of grant is amortized to expense over the restriction period net of anticipated forfeitures. Other stock-
based awards, granted to directors in lieu of cash for retainers and meeting fees, are fully vested and are expensed at fair value on
the date of grant and are not included in the tables below.
The expense, deferred tax benefit, and current tax expense recognized related to restricted stock and other stock-based awards
in 2017, 2016 and 2015 is presented below (in thousands):
2017
2016
2015
Expense (a).......................................
Deferred tax benefit .........................
Current tax benefit recognized.........
_____________________
(a) Any capitalized costs related to these expenses is less than $0.3 million for all years.
1,049
318
908
183
2,594
2,997
$
$
$
2,755
964
43
76
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in
2017, 2016 and 2015 is presented below (in thousands):
2017
2016
2015
Aggregated intrinsic value...........
Fair value at grant date ................
$
$
3,711
2,803
$
2,515
1,993
3,451
3,327
The unvested restricted stock transactions for 2017 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, 2016 (b)...
109,393
$
Stock awards...............................................................
Vested..........................................................................
Forfeitures...................................................................
Restricted shares outstanding at December 31, 2017 (b)...
70,273
(68,470)
(4,961)
106,235
39.90
49.78
40.93
40.18
45.76
$
2,005
$
5,880
_______________________
(a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term
of the outstanding restricted stock of approximately one year.
(b) Excludes the stock based retention grant to the President and Chief Executive Officer ("CEO") of 27,624 shares. See "Restricted
Stock with a Market Condition (Performance Shares)" section below for further details.
The weighted average fair value per share at grant date for restricted stock and other stock-base awards granted during 2017,
2016 and 2015 were:
Weighted average fair value per share ............ $
49.78
$
40.95
$
37.17
2017
2016
2015
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 31, 2018
175%
68,379
$
1,499
2015-2017
$
3,569
January 25, 2017
32%
11,314
January 27, 2016
February 20, 2015
0%
0%
0
0
932
851
2014-2016
2013-2015
1,502
2012-2014
512
—
—
In 2018, 2019 and 2020, subject to meeting certain performance criteria and continuous service requirements, additional
performance shares could vest. In accordance with the FASB guidance related to stock-based compensation, the Company
recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service
period and the compensation expense is only adjusted for forfeitures. As of December 31, 2017, the maximum number of shares
that can be issued under the plan are 280,159 shares.
The fair value at the date of each separate grant of performance shares was based upon a Monte Carlo simulation. The Monte
Carlo simulation reflected the structure of the performance plan which calculates the share payout on performance of the Company
relative to a defined peer group over a three-year performance period based upon total return to shareholders. The fair value was
determined as the average payout of one million simulation paths discounted to the grant date using a risk-free interest rate based
upon the constant maturity treasury rate yield curve at the grant date. The expected volatility of total return to shareholders is
calculated in accordance with the performance shares' term structure and includes the volatilities of all members of the defined
peer group.
The outstanding performance share awards at the 100% performance level is summarized below:
Number
Outstanding
Weighted
Average
Grant Date
Fair Value
Unrecognized
Compensation
Expense (b)
Aggregate
Intrinsic Value
(In thousands)
(In thousands)
Performance shares outstanding at December 31, 2016 (a)..
Performance share awards ....................................................
Performance shares vested ....................................................
Performance shares expired ..................................................
Performance shares forfeited.................................................
166,444
$
51,493
(11,314)
(24,057)
(9,975)
34.40
42.62
26.36
26.36
39.53
Performance shares outstanding at December 31, 2017 (a)..
172,591
38.21
$
2,048
$
9,553
_______________________
(a) On December 15, 2015, the Company issued a stock based retention grant to the President and CEO of 27,624 shares in
accordance with the Amended and Restated 2007 LTIP that is eligible for vesting based on the achievement of certain
performance conditions and a five year service period, as stated in the CEO's employment agreement. The performance condition
was met as of November 2016 as determined by the Compensation Committee, and has been included in the beginning and
ending balance in the table above.
78
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
(b) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term
of the awards of approximately one year, except for the CEO retention grant.
A summary of information related to performance shares for 2017, 2016 and 2015 is presented below:
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) ..
42.62
$
38.11
$
35.72
298
512
2,012
704
—
—
1,655
579
—
—
1,042
365
2017
2016
2015
_____________________
(a) Based on a 100% performance level.
(b) Includes adjustments for estimated forfeitures.
(c) Includes CEO retention grant.
Repurchase Program
No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2017. Detail
regarding the Company's stock repurchase program are presented below:
Shares repurchased (b) ................................................................................
Cost, including commission (in thousands) ................................................ $
Total remaining shares available for repurchase at December 31, 2017.....
Since 1999
(a)
25,406,184
423,647
Authorized
Shares
393,816
______________________
(a) Represents repurchased shares and cost since inception of the stock repurchase program in 1999.
(b) Shares repurchased does not include 86,735 treasury shares related to employee compensation arrangements outside of the
Company's repurchase programs. Beginning in 2015, shares of the Company's common stock issued for employee benefit
and stock incentive plans have been issued from the shares repurchased and held in treasury stock. The Company awarded
256,929 shares, net of shares withheld for taxes, out of treasury stock during 2017.
The Company may in the future make purchases of shares of its common stock pursuant to its authorized program in open
market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares will
be available for issuance under employee benefit and stock incentive plans, or may be retired.
Dividend Policy
On December 29, 2017, the Company paid $13.6 million in quarterly cash dividends to shareholders. The Company paid a
total of $53.3 million, $49.6 million and $47.1 million in cash dividends during the twelve months ended December 31, 2017,
2016 and 2015, respectively. On February 1, 2018, the Board of Directors declared a quarterly cash dividend of $0.335 per share
payable on March 30, 2018 to shareholders of record as of the close of business on March 16, 2018.
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,
2016
2017
2015
Weighted average number of common shares outstanding:
Basic number of common shares outstanding ...............................................
Dilutive effect of unvested performance awards ...................................
Diluted number of common shares outstanding ............................................
40,414,556
120,635
40,535,191
40,350,688
57,345
40,408,033
40,274,986
33,576
40,308,562
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 ................................................... $
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
$
$
$
$
$
$
$
$
81,918
(243)
81,675
81,918
(243)
81,675
1.165
0.865
2.030
1.165
0.865
2.030
The amount of restricted stock awards and performance shares at 100% performance level excluded from the calculation of
the diluted number of common shares outstanding because their effect was antidilutive is presented below:
Restricted stock awards ............................................
Year Ended December 31,
2016
53,703
2017
67,739
Performance shares (a) .............................................
—
47,246
2015
56,375
66,804
_____________________
(a) Certain performance shares were excluded from the computation of diluted earnings per share as no payouts would have
been required based upon performance at the end of each corresponding period.
80
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
H.
Accumulated Other Comprehensive Income (Loss)
Changes in Accumulated Other Comprehensive Income (Loss) (net of tax) by component are presented below (in thousands):
Unrecognized
Pension and
Post-
retirement
Benefit Costs
Net Unrealized
Gains (Losses)
on Marketable
Securities
Net Losses on
Cash Flow
Hedges
Accumulated
Other
Comprehensive
Income (Loss)
Balance at December 31, 2014............................ $
(34,884) $
38,957
$
(12,074)
$
(8,001)
Other comprehensive income (loss) before
reclassifications..........................................
3,777
(2,255)
Amounts reclassified from accumulated other
comprehensive income (loss)...................
Balance at December 31, 2015............................
Other comprehensive income before
reclassifications..........................................
Amounts reclassified from accumulated other
comprehensive income (loss)...................
Balance at December 31, 2016............................
Other comprehensive income before
reclassifications..........................................
Amounts reclassified from accumulated other
comprehensive income (loss)...................
Balance at December 31, 2017............................ $
1,522
(7,435)
(13,914)
14,267
(7,469)
(7,116)
28,202
(10,028)
11,058
1,238
(29,869)
7,363
(1,422)
(23,928)
7,951
(8,937)
27,765
6,904
(6,206)
28,463
20,251
—
264
(11,810)
—
159
(11,651)
—
(1,813)
(17,790) $
(8,524)
40,190
$
309
(11,342)
$
81
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Amounts reclassified from Accumulated Other Comprehensive Income (Loss) for the twelve months ended December 31,
2017, 2016 and 2015 are as follows (in thousands):
2017
2016
2015
Affected Line Item
in the Statements
of Operations
Details about Accumulated Other
Comprehensive Income (Loss)
Components
Amortization of pension and post-
retirement benefit costs:
Prior service benefit .............................
Net loss.................................................
Income tax effect..................................
$
9,657
$
(6,776)
2,881
(1,068)
1,813
7,407
(4,965)
2,442
(1,020)
1,422
Marketable securities:
Net realized gain on sale of securities..
10,626
7,640
Income tax effect..................................
10,626
(2,102)
8,524
7,640
(1,434)
6,206
Loss on cash flow hedge:
Amortization of loss.............................
Income tax effect..................................
(532)
(532)
223
(309)
(498)
(498)
339
(159)
$
6,574 (a)
(8,622) (a)
(2,048) (a)
810 Income tax expense
(1,238) Net income
11,114
Investment and
interest income, net
Income before
income taxes
11,114
(2,177) Income tax expense
8,937 Net income
(467)
Interest on long-
term debt and
revolving credit
facility
Income before
income taxes
(467)
203 Income tax expense
(264) Net income
Total reclassifications...........................
$
10,028
$
7,469
$
7,435
(a) These items are included in the computation of net periodic benefit cost. See Part II, Item 8, Financial Statements and
Supplementary Data, Note M for additional information.
82
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
I.
Long-Term Debt and Financing Obligations
Outstanding long-term debt and financing obligations, net of issuance costs, are as follows:
Long-Term Debt:
Pollution Control Bonds (1):
7.25% 2009 Series A refunding bonds, due 2040 (7.46% effective interest rate)............ $
4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate)............
7.25% 2009 Series B refunding bonds, due 2040 (7.49% effective interest rate)............
1.875% 2012 Series A refunding bonds, due 2032 (2.35% effective interest rate)..........
Total Pollution Control Bonds.................................................................................
Senior Notes (2):
6.00% Senior Notes, net of discount, due 2035 (6.58% effective interest rate)...............
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)...............
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)...............
5.00% Senior Notes, net of discount, due 2044 (4.93% effective interest rate)...............
Total Senior Notes ...................................................................................................
RGRT Senior Notes (3):
December 31,
2017
2016
(In thousands)
$
62,657
58,501
36,518
—
157,676
394,040
147,384
149,101
302,901
993,426
62,619
58,471
36,492
33,193
190,775
393,861
147,331
148,939
302,955
993,086
4.47% Senior Notes, Series B, due 2017 (4.62% effective interest rate).........................
5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate).........................
Total RGRT Senior Notes .......................................................................................
Total long-term debt .......................................................................................
—
44,886
44,886
1,195,988
49,950
44,845
94,795
1,278,656
Financing Obligations:
Revolving Credit Facility (4)...................................................................................................
Total long-term debt and financing obligations......................................................
173,533
1,369,521
81,574
1,360,230
Current Portion (amount due within one year):
Current maturities of long term debt ................................................................................
Short-term borrowings under the revolving credit facility...............................................
—
(173,533)
$ 1,195,988
(83,143)
(81,574)
$ 1,195,513
_____________________
(1) Pollution Control Bonds ("PCBs")
The Company had four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. In September
2017, the $33.3 million 2012 Series A 1.875% PCBs, which were subject to mandatory tender for purchase, were redeemed
and retired utilizing funds borrowed under the RCF. As of December 31, 2017, the Company's aggregate principal amount
on PCBs was $159.8 million. The 7.25% 2009 Series A and the 7.25% 2009 Series B PCBs with an aggregate principal
amount, together, of $100.6 million have optional redemptions beginning in February 2019 and April 2019, respectively.
(2) Senior Notes
The Senior Notes are unsecured obligations of the Company. They were issued pursuant to bond covenants that provide
limitations on the Company’s ability to enter into certain transactions. The 6.00% Senior Notes have an aggregate principal
amount of $400.0 million and were issued in May 2005. The proceeds, net of a $2.3 million discount, were used to fund the
retirement of the Company's first mortgage bonds. The Company amortizes the loss associated with a cash flow hedge recorded
in accumulated other comprehensive income to earnings as interest expense over the life of the 6.00% Senior Notes. See Part
II, Item 8, Financial Statements and Supplementary Data, Note O. This amortization is included in the effective interest rate
of the 6.00% Senior Notes.
83
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The 7.50% Senior Notes have an aggregate principal amount of $150.0 million and were issued in June 2008. The proceeds,
net of a $1.3 million discount, were used to repay short-term borrowings of $44.0 million, fund capital expenditures and for
other general corporate purposes.
The 3.30% Senior Notes have an aggregate principal amount of $150.0 million were issued in December 2012. The proceeds,
net of a $0.3 million discount, were used to fund construction expenditures and for working capital and general corporate
purposes.
In December 2014, the Company issued 5.00% Senior Notes with an aggregate principal amount of $150.0 million. The
proceeds, net of a $0.5 million discount, were used to fund construction expenditures and for working capital and general
corporate purposes. In March 2016, the Company issued additional 5.00% Senior Notes with an aggregate principal amount
of $150.0 million. The proceeds from this issuance, after deducting the underwriters' commission, were $158.1 million. These
proceeds included accrued interest of $2.4 million and a $7.1 million premium before expenses. The net proceeds, from the
sale of these senior notes were used to repay outstanding short-term borrowings under the RCF. After the March 2016 issuance,
the Company's 5.00% Senior Notes due 2044 had a total principal amount outstanding of $300.0 million.
(3) RGRT Senior Notes
In 2010, the Company and RGRT, a Texas grantor trust through which the Company finances its portion of fuel for Palo Verde,
entered into a note purchase agreement with various institutional purchasers. Under the terms of the agreement, RGRT sold
to the purchasers $110 million aggregate principal amount of Senior Notes ("RGRT Notes"). In August 2015 and 2017, $15.0
million and $50.0 million of these RGRT Notes, respectively, matured and were paid with borrowings from the RCF. The
Company guarantees the payment of principal and interest on the RGRT Notes. In the Company’s financial statements, the
assets and liabilities of RGRT are reported as assets and liabilities of the Company.
RGRT pays interest on the RGRT Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the
RGRT Notes, in whole or in part, at any time at a redemption price equal to 100% of the principal amount to be redeemed
together with the interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on
the prevailing market interest rates. The agreement requires compliance with certain covenants, including a total debt to
capitalization ratio. The Company was in compliance with these requirements throughout 2017.
The sale of the RGRT Notes was made by RGRT in reliance on a private placement exemption from registration under the
Securities Act of 1933, as amended. The proceeds of $109.4 million, net of issuance costs, from the sale of the RGRT Notes
was used by RGRT to repay amounts borrowed under the RCF and will enable future nuclear fuel financing requirements of
RGRT to be met with a combination of the RGRT Notes and amounts borrowed from the RCF.
(4) Revolving Credit Facility
On January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the
RCF with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication
agent, and various lending banks party thereto. As of December 31, 2016, the Company had available $300 million and the
ability to increase the RCF by up to $100 million with a term ending January 2019. On January 9, 2017, the Company exercised
its option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50
million to $350 million. The Company still has the option to extend the facility by one additional year to January 2021 and
to increase the RCF by up to $50 million (up to a total of $400 million) upon the satisfaction of certain conditions, more fully
set forth in the agreement, including obtaining commitments from lenders or third party financial institutions.
The RCF provides that amounts borrowed by the Company may be used for, among other things, working capital and general
corporate purposes. Any amounts borrowed by RGRT may be used, among other things, to finance the acquisition and
processing of nuclear fuel. Amounts borrowed by RGRT are guaranteed by the Company and the balance borrowed under
the RCF is recorded as short-term borrowings on the balance sheet. The RCF is unsecured. The RCF requires compliance
with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements
throughout 2017. In August 2015 and 2017, $15.0 million aggregate principal amount of Series A 3.67% Senior Notes and
$50.0 million aggregate principal amount of Series B 4.47% Senior Notes of RGRT, respectively, matured and were paid with
borrowings from the RCF. As of December 31, 2017, the total amount borrowed by RGRT was $88.5 million for nuclear fuel
84
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
under the RCF. As of December 31, 2017, $85.0 million of borrowings were outstanding under this facility for working capital
and general corporate purposes. The weighted average interest rate on the RCF was 2.7% as of December 31, 2017.
As of December 31, 2017, the principal amount of scheduled maturities for the next five years of long-term debt are as follows
(in thousands):
2018....................................................... $
2019.......................................................
2020.......................................................
2021.......................................................
2022.......................................................
—
—
45,000
—
—
J.
Income Taxes
On December 22, 2017, the TCJA was enacted. The TCJA includes significant changes to the IRC, including amendments
which significantly changed the taxation of business entities and includes specific provisions related to regulated public utilities.
The more significant changes that impact the Company included in the TCJA are reductions in the corporate federal income tax
rate from 35% to 21%, elimination of the corporate alternative minimum tax provision, additional limitations on deductions of
executive compensation, and limitations on the utilization of NOLs arising after December 31, 2017, to 80% of taxable income
with no carryback but with an indefinite carryforward. The specific provisions related to regulated public utilities in the TCJA
generally provide for the continued deductibility of interest expense, the elimination of bonus depreciation for property acquired
and placed into service after September 27, 2017, and the continuance of rate normalization requirements for accelerated
depreciation benefits and changes to deferred tax balances as a result of the change in the corporate federal income tax rate.
The results for the twelve months ended December 31, 2017 contain provisional estimates of the impact of the TCJA. These
amounts are considered provisional because they use estimates for which tax returns have not yet been filed and because estimated
amounts may be impacted by future regulatory and accounting guidance if and when issued. The Company will adjust these
provisional amounts as further information becomes available and as we refine our calculations. As permitted by recent guidance
issued by the Securities and Exchange Commission, these adjustments will occur during a reasonable “measurement period” not
to exceed twelve months from the date of enactment.
Provisional reductions in accumulated deferred federal income taxes ("ADFIT") due to the reduction in the corporate income
tax rate to 21% under the provisions of the TCJA will result in amounts previously collected from utility customers for these
deferred taxes to be refundable to such customers, generally through reductions in future rates. The TCJA includes provisions that
stipulate how these excess deferred taxes are to be returned to customers for certain accelerated tax depreciation benefits. Potential
refunds of other deferred taxes will be determined by the Company’s regulators. The December 31, 2017 balance sheet reflects
the impact of the TCJA which reduced ADFIT by $298.9 million, reduced regulatory assets by $23.6 million and increased
regulatory liabilities by $275.3 million. The changes in deferred taxes were recorded at the amount of the reduced future cash flow
expected to be included in rates, as required in ASC 740. These adjustments had no impact on the Company’s cash flows for the
year ended December 31, 2017.
In February 2018, the FASB issued ASU 2018-02, as a result of concerns raised by stakeholders due to the TCJA. ASU
2018-02 addresses concerns that the tax reduction due to the change in the corporate tax rate from 35% to 21% would be “stranded”
in AOCI. ASU 2018-02 allows companies to reclassify stranded taxes from AOCI to retained earnings. The Company is currently
in the process of evaluating the impact of ASU 2018-02 and its impact on regulated utilities. At December 31, 2017, the Company
has $7.2 million in stranded taxes in AOCI.
The provisional tax effects of temporary differences that give rise to significant portions of the deferred tax assets and
liabilities at December 31, 2017 and 2016 are presented below (in thousands):
85
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31,
2017
2016
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............................................................................................................................
Total gross deferred tax assets..........................................................................................
$
24,035
16,620
32,606
19,530
63,794
1,405
157,990
60,749
16,620
57,756
26,929
—
—
162,054
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences ...................................................
Decommissioning ....................................................................................................................
Deferred fuel............................................................................................................................
Other ........................................................................................................................................
Total gross deferred tax liabilities ....................................................................................
Net accumulated deferred income taxes ................................................................. $
(426,077)
(34,520)
—
(2,416)
(463,013)
(305,023) $
(668,303)
(43,463)
(3,962)
(1,392)
(717,120)
(555,066)
Based on the average annual earnings before taxes for the prior three years, and excluding the effects of unusual or infrequent
items, the Company believes that the deferred tax assets will be fully realized.
The Company recognized income tax expense for 2017, 2016 and 2015 as follows (in thousands):
Years Ended December 31,
2017
2016
2015
Income tax expense:
Federal:
Current .................................................................................................... $
Deferred ..................................................................................................
Total federal income tax................................................................
State:
Current ....................................................................................................
Deferred ..................................................................................................
Total state income tax....................................................................
Generation (amortization) of accumulated investment tax credits ................
Total income tax expense............................................................... $
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
$
$
2,319
32,819
35,138
1,730
(1,650)
80
(323)
34,895
As of December 31, 2017, the Company had $16.6 million of AMT credit carryforwards. Based on the TCJA provisions,
the Company may claim a refund of 50% of the remaining AMT credits (to the extent the credits exceed the Company's regular
tax liability for the year) in 2018, 2019, and 2020. Any AMT credits remaining after 2020 will be refunded in 2021. As of
December 31, 2017, the Company had $23.0 million of federal and $1.4 million of state tax loss carryforwards. Under the TCJA,
NOLs arising in tax years ending after 2017 cannot be carried back but can be carried forward indefinitely. The use of NOLs
generated after 2017 to offset taxable income is limited to 80% of taxable income. Federal NOLs generated prior to 2018 are able
to offset 100% of future taxable income to the extent available but have lives of only 20 years.
Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 35% to book
income before federal income tax as follows (in thousands):
86
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
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,
2017
52,243
2016
52,740
$
2015
40,885
$
597
450
(2,562)
276
51,004
$
2,633
(475)
(2,369)
1,389
53,918
$
52
(2,345)
(2,898)
(799)
34,895
Effective income tax rate ......................................................................................
34.2%
35.8%
29.9%
The Company files income tax returns in the United States federal jurisdiction and in the states of Texas, New Mexico and
Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal, Arizona and New Mexico
jurisdictions for years prior to 2013. In August 2017, the Company reached an agreement with the Texas Comptroller of Public
Accounts and settled audits in Texas for tax years 2007 through 2011.
In the third quarter of 2016, the Company changed its accounting for state income taxes from the flow-through method to
the normalization method in accordance with the 2016 PUCT Final Order and the NMPRC Final Order. Under the flow-through
method, the Company previously recorded deferred state income taxes and regulatory liabilities and assets offsetting such deferred
state income taxes at the expected cash flow to be reflected in future rates. Upon implementation of normalization, the Company
began amortizing the net regulatory asset for deferred state income taxes to deferred income tax expense over a 15 year period as
allowed by the regulators. In the third quarter of 2016, the Company began recording deferred state income tax expense as required
by normalization, retroactive to January 2016 as provided in the final orders. The impact of the change was additional income
tax expense of $1.9 million and $5.1 million for the years ended December 31, 2017 and 2016, respectively.
The FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition
and measurement of a tax position taken or expected to be taken in a tax return. The Company recorded a decrease of $1.2 million
(net of an increase of $0.5 million), a decrease of $0.4 million (net of an increase of $0.3 million), and an unrecognized tax position
of $0.8 million, in 2017, 2016, and 2015 respectively, related to transmission and distribution costs and other amounts deducted
in current and prior year Texas franchise tax returns. The Company recorded an unrecognized tax position of $0.1 million in 2017
and a decrease of $0.3 million in 2016 related to tax credits taken and apportionment factors used in prior year Arizona income
tax returns, which have been settled through audit. A reconciliation of the December 31, 2017, 2016 and 2015 amounts of
unrecognized tax benefits are as follows (in thousands):
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 ....................................................................................... $
5,300
200
—
400
(1,700)
4,200
$
$
6,000
400
—
100
(1,200)
5,300
$
$
5,200
500
—
300
—
6,000
2017
2016
2015
If recognized, $1.1 million of the unrecognized tax position at December 31, 2017, would reduce the effective tax rate. The
Company recognized an income tax benefit for the decrease in unrecognized tax positions of $1.1 million for the year ended
December 31, 2017.
The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. For the
year ended December 31, 2017, the Company recognized a benefit of $0.2 million. For the years ended December 31, 2016, and
2015 the Company recognized interest expense of $0.1 million, and $0.2 million, respectively. The Company had approximately
$0.7 million and $0.8 million accrued for the payment of interest and penalties at December 31, 2017 and 2016, respectively.
87
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
K.
Commitments, Contingencies and Uncertainties
Power Purchase and Sale Contracts
To supplement its own generation and operating reserve requirements and to meet required renewable portfolio standards,
the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the
Company’s resource needs, the economics of the transactions and specific renewable portfolio requirements. The Company has
entered into the following significant agreements with various counterparties for the purchase and sale of electricity:
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
2018
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................
NRG
20 MW
August 2011 through August 2031
August 2011
Power Purchase Agreement................
SunE EPE1, LLC
Power Purchase Agreement................
SunE EPE2, LLC
10 MW
12 MW
June 2012 through June 2037
May 2012 through May 2037
June 2012
May 2012
Power Purchase Agreement................
Macho Springs Solar, LLC
50 MW
May 2014 through May 2034
May 2014
Power Purchase Agreement................
Newman Solar LLC
10 MW
December 2014 through December
2044
December 2014
The Company has a firm Power Purchase and Sale Agreement with Freeport-McMoran Copper & Gold Energy Services
LLC ("Freeport") that provides for Freeport to deliver energy to the Company from the Luna Energy Facility (a natural gas-fired
combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy
at Greenlee, Arizona. The Company may purchase the quantities noted in the table above at a specified price at times when energy
is not exchanged under the Power Purchase and Sale Agreement. The agreement was approved by the FERC and will continue
through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power
Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold under the agreement.
The parties have agreed to increase the amount up to 125 MW through December 2018.
The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements. Namely,
the Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC to purchase all of the output from
a solar photovoltaic plant located in southern New Mexico which began commercial operation in July 2011. In June 2015, the
Company entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement
photovoltaic modules. The Company also entered into a 20-year contract with NRG Solar Roadrunner LLC ("NRG") to purchase
all of the output of a solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011.
In addition, the Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic
plants located in southern New Mexico, SunE EPE1, LLC and SunE EPE2, LLC which began commercial operation in June 2012
and May 2012, respectively. In September 2017, Longroad Solar Portfolio Holdings, LLC purchased SunE EPE1, LLC and in
October 2017, Silicon Ranch Corporation purchased SunE EPE2, LLC with the Company's consent per the terms of both purchase
power agreements.
Furthermore, the Company has a 20-year purchase power agreement with Macho Springs Solar, LLC to purchase the entire
generation output delivered from the 50 MW Macho Springs solar photovoltaic plant located in Luna County, New Mexico which
began commercial operation in May 2014. Finally, the Company has a 30-year purchase power agreement with Newman Solar
LLC to purchase the total output of approximately 10 MW from a solar photovoltaic plant on land subleased from the Company
in proximity to its Newman Power Station ("Newman"). This solar photovoltaic plant began commercial operation in
December 2014.
88
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Environmental Matters
General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and greenhouse
gas ("GHG") emissions, water discharges, soil and water quality, waste management and disposal, natural resources and other
environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and
requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative,
civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result
in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation,
or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to
comply.
Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the
EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The
allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the
controls necessary under the CAA to reduce sulfur dioxide ("SO2"), nitrogen oxides ("NOx"), and particulate matter ("PM"), and
that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by
law. On June 24, 2015, the parties filed with the U.S. District Court for New Mexico a settlement agreement ("CAA Settlement
Agreement") resolving this matter. On August 17, 2015, the U.S. District Court for New Mexico entered the CAA Settlement
Agreement. The agreement imposes a total civil penalty payable by the co-owners of Four Corners collectively in the amount of
$1.5 million, and it requires the co-owners to pay $6.7 million for environmental mitigation projects. At December 31, 2017, the
Company has accrued its remaining unpaid share of approximately $0.2 million related to this matter.
Lease Agreements
The Company leases land in El Paso, Texas, adjacent to Newman under a lease which expires in June 2033 with a renewal
option of 25 years. The Company also has several other leases for office, parking facilities and equipment which expire within the
next 5 years. The Company has transmission and distribution lines which are operated under various land rights agreements,
including easements, leases, permits and franchises. The majority of these agreements include renewal options which the Company
routinely exercises. These agreements generally do not impose any restrictions relating to issuance of additional debt, payment of
dividends or entering into other lease arrangements. The Company has no significant capital lease agreements.
The Company's total annual rental expense related to operating leases was $2.4 million, $1.7 million, and $1.9 million for
2017, 2016 and 2015, respectively. As of December 31, 2017, the Company’s minimum future rental payments for the next five
years are as follows (in thousands):
2018................................................. $
2019.................................................
2020.................................................
2021.................................................
2022.................................................
951
893
820
675
595
Union Matters
The Company has approximately 1,100 employees, about 38% of whom are covered by a collective bargaining agreement.
The International Brotherhood of Electrical Workers Local 960 ("Local 960") represents the Company’s employees working
primarily in the power plants, substations, line crews, meter reading and collection, facilities services, and customer service. The
Company entered into a new collective bargaining agreement effective September 3, 2016, with Local 960 for a three-year term
ending September 3, 2019. The agreement provides for pay increases of 3% on September 3, 2016, September 3, 2017 and on
September 3, 2018, respectively.
89
L.
Litigation
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory
commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters,
the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly
analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual
disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the
matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect
on the financial position, results of operations or cash flows of the Company. The Company expenses legal costs, including expenses
related to loss contingencies, as they are incurred.
See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note K for discussion of the effects of
government legislation and regulation on the Company as well as certain pending legal proceedings.
90
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
M.
Employee Benefits
Retirement Plans
The Company’s Retirement Income Plan (the "Retirement Plan") is a qualified noncontributory defined benefit plan. Upon
retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement
Plan. Contributions from the Company are based on various factors, such as the minimum funding amounts required by the Internal
Revenue Service ("IRS"), state and federal regulatory requirements, amounts requested from customers in the Company's Texas
and New Mexico jurisdictions, and the annual net periodic benefit cost of the Retirement Plan, as actuarially calculated. The assets
of the Retirement Plan are primarily invested in common collective trusts which hold equity securities, debt securities and cash
equivalents and are managed by a professional investment manager appointed by the Company.
The Company has two non-qualified retirement plans that are non-funded defined benefit plans. The Company's Supplemental
Retirement Plan covers certain former employees and directors of the Company. The Excess Benefit Plan was adopted in 2004
and covers certain active and former employees of the Company. The net periodic benefit cost for the non-qualified retirement
plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.
The Retirement Plan was amended effective April 1, 2014 to offer a cash balance pension benefit as an alternative to its
existing final average pay pension benefit for employees hired prior to January 1, 2014. Employees hired after January 1, 2014
are automatically enrolled in the cash balance pension benefit.
Prior to December 31, 2013, employees who completed one year of service with the Company and worked at least a minimum
number of hours each year were covered by the final average pay formula of the plan. For participants that continue to be covered
by the final average pay formula, retirement benefits are based on the employee’s final average pay and years of service. The cash
balance pension benefit covers employees beginning on their employment commencement date or re-employment commencement
date. Retirement benefits under the cash balance pension benefit are based on the employee’s cash balance account, consisting of
pay credits and interest credits.
The obligations and funded status of the plans are presented below (in thousands):
December 31,
2017
2016
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Change in projected benefit obligation:
Benefit obligation at end of prior year................ $
Service cost.........................................................
Interest cost.........................................................
Actuarial 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 on plan assets................................
Employer contribution ........................................
Benefits paid .......................................................
Fair value of plan assets at end of year........
Funded status at end of year ........................ $
$
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) $
$
325,706
7,705
12,161
7,988
(15,792)
337,768
260,035
18,223
7,300
(15,792)
269,766
(68,002) $
26,958
296
878
1,267
(1,937)
27,462
—
—
1,937
(1,937)
—
(27,462)
91
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Amounts recognized in the Company's balance sheets consist of the following (in thousands):
December 31,
2017
2016
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Current liabilities ......................................................................... $
Noncurrent liabilities ...................................................................
Total...................................................................................... $
— $
(57,600)
(57,600) $
(2,154) $
(26,238)
(28,392) $
— $
(68,002)
(68,002) $
(2,696)
(24,766)
(27,462)
The accumulated benefit obligation in excess of plan assets is as follows (in thousands):
December 31,
2017
2016
Projected benefit obligation......................................................... $
Accumulated benefit obligation ..................................................
Fair value of plan assets ..............................................................
Retirement
Income
Plan
(361,989) $
(329,279)
304,389
Non-Qualified
Retirement
Plans
(28,392) $
(25,370)
—
Retirement
Income
Plan
(337,768) $
(314,071)
269,766
Non-Qualified
Retirement
Plans
(27,462)
(25,550)
—
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,
2017
2016
Retirement
Income
Plan
109,215
(20,410)
88,805
Non-Qualified
Retirement
Plans
$
$
11,408
(146)
11,262
$
$
Retirement
Income
Plan
121,052
(23,877)
97,175
Non-Qualified
Retirement
Plans
$
$
10,073
(185)
9,888
The following are the weighted-average actuarial assumptions used to determine the benefit obligations:
December 31,
2017
Non-Qualified
2016
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....
3.77%
4.5%
3.40%
N/A
3.81%
4.5%
4.29%
4.5%
3.76%
N/A
4.34%
4.5%
The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed and updated
at each measurement date. The discount rate used to measure the fiscal year end obligation is based on a segmented spot rate yield
curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future
benefit payments. A 1% increase in the discount rate would decrease the December 31, 2017 retirement plans' projected benefit
obligation by 12.4%. A 1% decrease in the discount rate would increase the December 31, 2017 retirement plans' projected benefit
obligation by 15.6%.
92
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The components of net periodic benefit cost are presented below (in thousands):
Years Ended December 31,
2017
2016
2015
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
$
8,156
12,196
(19,189)
7,572
(3,467)
362
863
—
882
(39)
$
$
7,705
12,161
(18,879)
6,554
(3,467)
296
878
—
785
(39)
$
$
8,530
13,477
(19,795)
9,710
(3,467)
262
1,018
—
937
(39)
5,268
$
2,068
$
4,074
$
1,920
$
8,455
$
2,178
Service cost .............................. $
Interest cost ..............................
Expected return on plan assets.
Amortization of:
Net loss .............................
Prior service benefit..........
Net periodic benefit
cost............................. $
In 2016, the Company changed the method used to estimate the service and interest components of net periodic benefit
cost for pension benefits. This change, compared to the previous method, resulted in a decrease of approximately $2.9 million in
the service cost and interest cost components in 2016. Historically, the Company estimated service and interest costs utilizing a
single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the
period. In 2016, the Company elected to utilize a full yield curve approach to estimate these components by applying the specific
spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. The
Company believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of
the plan’s liability cash flows to the corresponding spot rates on the yield curve. The Company accounted for this change as a
change in accounting estimate and accordingly, accounted for this prospectively.
The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):
2017
2016
2015
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
(4,265) $
2,217
$
8,644
$
1,266
$
4,266
$
(811)
(7,572)
3,467
(882)
39
(6,554)
3,467
(785)
39
(9,710)
3,467
(937)
39
(8,370) $
1,374
$
5,557
$
520
$
(1,977) $
(1,709)
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,
2017
2016
2015
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Total recognized in net
periodic benefit cost and other
comprehensive income ............. $
(3,102) $
3,442
$
9,631
$
2,440
$
6,478
$
469
93
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The following are amounts in accumulated other comprehensive income that are expected to be recognized as
components of net periodic benefit cost during 2018 (in thousands):
Net loss ............................................................................................................................... $
Prior service benefit............................................................................................................
7,450
(3,470)
Retirement Income
Plan
Non-Qualified
Retirement Plans
960
$
(40)
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the
twelve months ended December 31:
2017
Non-Qualified
2016
Non-Qualified
2015
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 ..............
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%
4.87%
N/A
3.04%
3.9%
4.0%
4.0%
4.0%
3.4%
N/A
3.4%
4.1%
4.1%
4.1%
7.0%
N/A
N/A
7.0%
N/A
N/A
7.5%
N/A
N/A
4.5%
N/A
4.5%
4.5%
N/A
4.5%
4.5%
N/A
4.5%
The Company’s overall expected long-term rate of return on assets is 7.5% effective January 1, 2018, which is both a pre-
tax and after-tax rate as pension funds are generally not subject to income tax. The expected long-term rate of return is based on
the weighted average of the expected returns on investments based upon the target asset allocation of the pension fund. The
Company’s target allocations for the plan’s assets are presented below:
Equity securities ..............................
Fixed income ...................................
Alternative investments ...................
Total ......................................
December 31, 2017
50%
40%
10%
100%
As of January 1, 2018, the long-term rate of return assumption was updated to be gross of administrative expenses paid to
the trust. Net of administrative expenses, the reported long-term rate of return would have been 7.0%.
The Retirement Plan invests the majority of its plan assets in common collective trusts which includes a diversified portfolio
of domestic and international equity securities and fixed income securities. Alternative investments of the Retirement Plan are
comprised of a real estate limited partnership and equity securities of real estate companies, primarily in real estate investment
trusts, and other property trusts. The expected rate of returns for the funds are assessed annually and are based on long-term
relationships among major asset classes and the level of incremental returns that can be earned by the successful implementation
of different active investment management strategies. Equity and real estate equity returns are based on estimates of long-term
inflation rate, real rate of return, 10-year Treasury bond premium over cash, an expected equity risk premium, as well as other
economic factors. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads. These
assumptions also capture the expected correlation of returns between these asset classes over the long term.
94
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The FASB guidance on disclosure for pension plans requires disclosure of fair value measurements of plan assets. To increase
consistency and comparability in fair value measurements, the FASB guidance on fair value measurements established a fair value
hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•
•
•
Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices
of securities held in the mutual funds and underlying portfolios of the Retirement Plan are primarily obtained from
independent pricing services. These prices are based on observable market data. The Common Collective Trusts are
valued using the Net Asset Value ("NAV") provided by the administrator of the fund. The NAV price is quoted on a
restrictive market although the underlying investments are traded on active markets. The NAV used for determining the
fair value of the investments in the Common Collective Trusts have readily determinable fair values. Accordingly, such
fund values are categorized as Level 1.
Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either
directly or indirectly. The fair value of these investments are based on evaluated prices that reflect observable market
information, such as actual trade information of similar securities, adjusted for observable differences.
Level 3 – Unobservable inputs using data that is not corroborated by market data.
95
—
—
—
—
—
—
—
—
—
—
—
—
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The fair value of the Company’s Retirement Plan assets at December 31, 2017 and 2016, and the level within the three levels
of the fair value hierarchy defined by the FASB guidance on fair value measurements are presented in the table below (in thousands):
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 estate funds ......................................................................
Total Common Collective Trusts..........................................
Limited Partnership Interest in Real Estate (b)(c).......................
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
$
— $
Fair Value as of
December 31,
2016
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
932
$
932
$
— $
Description of Securities
Cash and Cash Equivalents ......................................................... $
Common Collective Trusts (a)
Equity funds .............................................................................
Fixed income funds..................................................................
Real estate funds ......................................................................
Total Common Collective Trusts..........................................
Limited Partnership Interest in Real Estate (b)(c).......................
Total Plan Investments ......................................................... $
144,081
109,356
8,406
261,843
6,991
269,766
144,081
109,356
8,406
261,843
—
—
—
—
$
262,775
$
— $
_____________________
(a) The Common Collective Trusts are invested in equity and fixed income securities, or a combination thereof. The investment
objective of each fund is to produce returns in excess of, or commensurate with, its predefined index.
(b) This investment is a commercial real estate partnership that purchases land, develops limited infrastructure, and sells it for
commercial development. The Company was restricted from selling its partnership interest during the life of the partnership,
which spanned 7 years. Return on investment is realized as land is sold. The fair value of the limited partnership interest in
real estate is based on the NAV of the partnership which reflects the appraised value of the land. The partnership term expired
on June 30, 2016. Upon expiration, dissolution of the partnership commenced and, as a result, the general partner of the
partnership is attempting to sell the remaining inventory as soon as possible at the highest pricing possible.
In the first quarter of 2016, the Company implemented ASU 2015-07, Fair Value Measurement (Topic 820) which eliminates
the requirement to categorize investments in the fair value hierarchy if the fair value is measured at NAV per share (or its
equivalent) using the practical expedient in the FASB’s fair value measurement guidance. The fair value amounts presented
in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of
financial position.
(c)
96
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The table below reflects the changes in the fair value of investments in the real estate limited partnership during the period
(in thousands):
Fair Value of
Investments in
Real Estate
Balances at December 31, 2015 .................................................................................. $
Sale of land...........................................................................................................
Unrealized loss in fair value.................................................................................
Balances at December 31, 2016 ..................................................................................
Sale of land...........................................................................................................
Unrealized loss in fair value.................................................................................
Balances at December 31, 2017 .................................................................................. $
8,588
(775)
(822)
6,991
(2,687)
(451)
3,853
There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable
inputs during the twelve month periods ending December 31, 2017 and 2016. There were no purchases, issuances, and settlements
related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2017
and 2016.
The Company and the fiduciaries responsible for the Retirement Plan adhere to the traditional capital market pricing theory
which maintains that over the long term, the risk of owning equities should be rewarded with a greater return than available from
fixed income investments. The Company and the fiduciaries responsible for the Retirement Plan seek to minimize the risk of
owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying its investments to limit
its risks during falling markets. The investment manager has full discretionary authority to direct the investment of plan assets
held in trust within the guidelines prescribed by the Company and the fiduciaries responsible for the Retirement Plan through the
plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment
policy statement are in accordance with the Employee Retirement Income Security Act of 1974 ("ERISA") and Department of
Labor ("DOL") regulations.
The Company contributes at least the minimum funding amounts required by the IRS for the Retirement Plan, as actuarially
calculated.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):
Retirement Income
Plan
2018 ........................................................................... $
2019 ...........................................................................
2020 ...........................................................................
2021 ...........................................................................
2022 ...........................................................................
2023-2027..................................................................
17,166
17,656
17,938
18,612
19,247
105,915
Non-Qualified
Retirement Plans
2,154
$
2,032
1,975
1,926
1,876
8,754
401(k) Defined Contribution Plans
The Company sponsors 401(k) defined contribution plans covering substantially all employees. The Company provides a
50 percent matching contribution up to 6 percent of the employee’s compensation for employees who are enrolled in the final
average pay pension benefit of the Retirement Plan and a 100 percent matching contribution up to 6 percent of the employee's
compensation for employees who are enrolled in the cash balance pension benefit of the Retirement Plan, subject to certain other
limits and exclusions. Annual matching contributions made to the savings plans for the years 2017, 2016 and 2015 were $4.4
million, $4.1 million, and $3.9 million, respectively.
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 (the "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, the IRS tax deductible limit, state and federal regulatory
97
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
requirements, amounts requested from customers in the Company's Texas and 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..............................................................................................................................
Interest cost..............................................................................................................................
Actuarial (gain) loss ................................................................................................................
Amendment (a)........................................................................................................................
Benefits paid............................................................................................................................
Retiree contributions ...............................................................................................................
Benefit obligation at end of year ......................................................................................
Change in plan assets:
Fair value of plan assets at end of prior year...........................................................................
Actual return on plan assets.....................................................................................................
Employer contribution.............................................................................................................
Benefits paid............................................................................................................................
Retiree contributions ...............................................................................................................
Fair value of plan assets at end of year ............................................................................
Funded status at end of year ........................................................................................ $
December 31,
2017
2016
$
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) $
92,643
2,769
3,167
10,751
(32,697)
(4,428)
1,310
73,515
38,090
2,443
1,700
(4,428)
1,310
39,115
(34,400)
_____________________
(a) During October 2016, the Company approved and communicated a plan amendment that resulted in a remeasurement of the
Company's Other Post-retirement Benefit Plan. Effective January 1, 2017, retirees and dependents that are less than 65 years
of age are offered a choice between a $1,000 and $2,250 deductible plan. Additionally, retirees and dependents that are 65
years of age or greater were covered by a fully insured Medicare advantage plan.
Amounts recognized in the Company's balance sheets consist of the following (in thousands):
Current liabilities ............................................... $
Noncurrent liabilities .........................................
— $
(26,417)
Total............................................................ $
(26,417) $
—
(34,400)
(34,400)
December 31,
2017
2016
Pre-tax amounts recognized in accumulated other comprehensive income consist of the following (in thousands):
Net gain ............................................................. $
Prior service benefit...........................................
Total............................................................ $
December 31,
2017
(35,194) $
(34,857)
(70,051) $
2016
(26,285)
(41,009)
(67,294)
98
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,
2017
2016
3.79%
4.36%
6.25%
4.50%
7.25%
10.00%
4.50%
2026
6.50%
4.50%
7.50%
10.50%
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, 2017 accumulated post-retirement benefit
obligation by 14.2%. A 1% decrease in the discount rate would increase the December 31, 2017 accumulated post-retirement
benefit obligation by 18.5%.
Net periodic benefit cost (benefit) is made up of the components listed below (in thousands):
Service cost ........................................................................................................... $
Interest cost ...........................................................................................................
Expected return on plan assets ..............................................................................
Amortization of:
Prior service benefit .......................................................................................
Net gain..........................................................................................................
Net periodic benefit cost (benefit) .......................................................... $
Years Ended December 31,
2017
2016
2015
$
2,236
2,723
(1,907)
(6,151)
(1,678)
(4,777) $
$
2,769
3,167
(1,835)
(3,901)
(2,374)
(2,174) $
3,454
4,035
(2,070)
(3,068)
(2,025)
326
In 2016, the Company changed the method used to estimate the service and interest components of net periodic benefit cost
for other post-retirement benefits. This change, compared to the previous method, resulted in a decrease of approximately $0.8
million in the service cost and interest cost components in 2016. Historically, the Company estimated service and interest costs
utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning
of the period. In 2016, the Company elected to utilize a full yield curve approach to estimate these components by applying the
specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows.
The Company believes the new approach provides a more precise measurement of service and interest costs by aligning the timing
of the plan’s liability cash flows to the corresponding spot rates on the yield curve. The Company accounted for this change as a
change in accounting estimate and accordingly, accounted for this prospectively.
99
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):
Years Ended December 31,
Net (gain) loss ....................................................................................................... $
Prior service benefit ..............................................................................................
Amortization of:
2017
(10,586) $
—
2016
2015
$
10,143
(32,697)
Prior service benefit .......................................................................................
Net gain..........................................................................................................
Total recognized in other comprehensive income................................................. $
6,151
1,678
(2,757) $
3,901
2,374
(16,279) $
(8,884)
(824)
3,068
2,025
(4,615)
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 .. $
(7,534) $
2017
2016
(18,453) $
2015
(4,289)
Years Ended December 31,
The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic
benefit cost during 2018 is a prior service benefit of $6.2 million and a net gain of $2.1 million.
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve
months ended December 31:
2017
2016 (a)
2015
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) ............................................
4.37%
4.59%
3.76%
4.875%
6.5%
4.5%
7.5%
10.5%
4.5%
2026
January 1 -
September 30
October 1 -
December 31
4.59%
4.91%
3.86%
4.875%
3.75%
4.03%
3.15%
7.0%
7.0%
7.0%
7.0%
4.5%
2026
4.1%
4.1%
4.1%
5.2%
7.25%
7.25%
7.25%
7.25%
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, 2017 benefit obligation
by $11.3 million or $8.8 million, respectively. In addition, a 1% change in said rate would increase or decrease the aggregate
2017 service and interest cost components of the net periodic benefit cost by $1.1 million or $0.8 million, respectively.
100
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The Company's overall expected long-term rate of return on assets is 7.85%, effective January 1, 2018, on a pre-tax basis.
The expected gross long-term rate of return on assets on an after-tax basis is 6.12% effective January 1, 2018. The trust's tax rate
was assumed to be 35% at January 1, 2017 and 22% at January 1, 2018. 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, 2017
48%
33%
19%
100%
As of January 1, 2018, the long-term rate of return assumption was updated to be gross of administrative expenses paid
from the trust. Net of administrative expenses, the reported long-term rate of return would have been 7.5%.
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 commercial real estate securities, known as 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 will
remain 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 are based on evaluated prices that reflect observable market
information, such as actual trade information of similar securities, adjusted for observable differences.
Level 3 – Unobservable inputs using data that is not corroborated by market data.
101
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The fair value of the Company’s OPEB Plan assets at December 31, 2017 and 2016, and the level within the three levels of
the fair value hierarchy defined by the FASB guidance on fair value measurements are presented in the table below (in thousands):
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 .................................................................
Real estate funds......................................................................
Total Institutional Funds ......................................................
Limited Partnership Interest in Real Estate (b) (c)......................
Total Plan Investments......................................................... $
19,862
17,823
1,657
39,342
722
40,873
19,862
17,823
1,657
39,342
—
—
—
—
$
40,151
$
— $
—
—
—
—
—
—
Description of Securities
Institutional Funds (a)
Fair Value as of
December 31,
2016
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Equity funds............................................................................. $
Fixed income funds .................................................................
Total Institutional Funds ......................................................
Limited Partnership Interest in Real Estate (b) (c)......................
Total Plan Investments......................................................... $
26,133
11,671
37,804
1,311
39,115
$
$
26,133
11,671
37,804
— $
—
—
$
37,804
$
— $
—
—
—
—
___________________
(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.
In the first quarter of 2016, the Company implemented ASU 2015-07, Fair Value Measurement (Topic 820) which eliminates
the requirement to categorize investments in the fair value hierarchy if the fair value is measured at NAV per share (or its
equivalent) using the practical expedient in the FASB’s fair value measurement guidance. The fair value amounts presented
in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of
financial position.
(c)
102
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, 2015......... $
Sale of land .................................
Unrealized loss in fair value .......
Balance at December 31, 2016.........
Sale of land .................................
Unrealized loss in fair value .......
Balance at December 31, 2017......... $
1,610
(145)
(154)
1,311
(504)
(85)
722
There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable
inputs during the twelve month periods ending December 31, 2017 and 2016. There were no purchases, issuances, and settlements
related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2017
and 2016.
The Company and the fiduciaries responsible for the 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 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):
2018 .................................................................................. $
2019 ..................................................................................
2020 ..................................................................................
2021 ..................................................................................
2022 ..................................................................................
2023-2027 .........................................................................
2,260
2,404
2,607
2,771
2,937
16,440
Annual Short-Term Incentive Plan
The Annual Short-Term Incentive Plan (the "Incentive Plan") provides for the payment of cash awards to eligible Company
employees, including each of its named executive officers. Payment of awards is based on the achievement of performance measures
reviewed and approved by the Company’s Board of Directors’ Compensation Committee. Generally, these performance measures
are based on meeting certain financial, operational and individual performance criteria. The financial performance goals are based
on earnings per share and certain operations and maintenance expenses. The operational performance goals are based on reliability,
customer satisfaction, and compliance. If a specified level of earnings per share is not attained, no amounts will be paid under the
Incentive Plan, unless the Compensation Committee determines otherwise. In 2017, the Company reached the required levels of
earnings per share, certain operations and maintenance expenses, customer satisfaction, and compliance goals for an incentive
payment of $9.7 million. In 2016 and 2015, the Company achieved required levels of similar goals for incentive payments of
$12.5 million and $10.5 million, respectively.
103
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
N.
Franchises and Significant Customers
Franchises
The Company operates under franchise agreements with several cities in its service territory, including one with El Paso,
Texas, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve
its customers within El Paso. Pursuant to the El Paso franchise agreement, which was amended in 2010, the Company pays to the
City of El Paso, on a quarterly basis, a fee equal to 4.00% of gross revenues the Company receives for the generation, transmission
and distribution of electrical energy and other services within the city. The 2005 El Paso franchise agreement set the franchise fee
at 3.25% of gross revenues, but the 2010 amendment added an incremental fee equal to 0.75% of gross revenues to be placed in
a restricted fund to be used by the city solely for economic development and renewable energy purposes. Any assignment of the
franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of
the City of El Paso. The El Paso franchise agreement is set to expire on July 31, 2030.
The Company does not have a written franchise agreement with Las Cruces, New Mexico, the second largest city in its
service territory. The Company utilizes public rights-of-way necessary to service its customers within Las Cruces under an implied
franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009. The Company pays the City
of Las Cruces a franchise fee of 2.00% of gross revenues the Company receives from services within the City of Las Cruces.
Military Installations
The Company serves HAFB, White Sands Missile Range ("White Sands") and Fort Bliss. These military installations
represent approximately 2.5% of the Company's annual retail revenues. In July 2014, the Company signed an agreement with
Fort Bliss under which Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company
serves White Sands under the applicable New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under
which the Company provides retail electric service and limited wheeling services to HAFB under the applicable New Mexico
tariffs. As stated in the contract, HAFB will purchase the full output of a Company-owned 5 MW solar facility upon its completed
construction, with HAFB's other power requirements and limited wheeling services provided under the applicable New Mexico
tariffs.
104
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
O.
Financial Instruments and Investments
The FASB guidance requires the Company to disclose estimated fair values for its financial instruments. The Company has
determined that cash and temporary investments, investment in debt securities, accounts receivable, decommissioning trust funds,
long-term debt, short-term borrowings under the RCF, accounts payable and customer deposits meet the definition of financial
instruments. The carrying amounts of cash and temporary investments, accounts receivable, accounts payable and customer
deposits approximate fair value because of the short maturity of these items. Investments in debt securities and decommissioning
trust funds are carried at 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,
2017
2016
Carrying
Amount
Estimated
Fair Value
Carrying
Amount
Estimated
Fair Value
Pollution Control Bonds (1) ........................................................ $
Senior Notes ................................................................................
RGRT Senior Notes (2) ...............................................................
RCF (2)........................................................................................
157,676
993,426
44,886
173,533
Total............................................................................... $ 1,369,521
$
169,186
1,211,922
47,070
173,533
$ 1,601,711
$
190,775
993,086
94,795
81,574
$ 1,360,230
$
206,818
1,112,285
98,855
81,574
$ 1,499,532
__________________
(1)
In September 2017, the $33.3 million 2012 Series A 1.875% Pollution Control Bonds which were subject to mandatory tender
for purchase were redeemed and retired utilizing funds borrowed under the RCF.
(2) Nuclear fuel financing, as of December 31, 2017 and December 31, 2016, is funded through $45 million and $95 million
RGRT Senior Notes and $88.5 million and $37.6 million, respectively under the RCF. In August 2017, RGRT's $50.0 million
Series B 4.47% Senior Notes matured and were paid utilizing funds borrowed under the RCF. As of December 31, 2017,
$85.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2016,
$44.0 million amount was outstanding under the RCF for working capital or general corporate purposes. The interest rate
on the Company’s borrowings under the RCF is reset throughout the period reflecting current market rates. Consequently,
the carrying value approximates fair value.
Treasury Rate Locks. The Company entered into treasury rate lock agreements in 2005 to hedge against potential movements
in the treasury reference interest rate pending the issuance of the 6% Senior Notes. The treasury rate lock agreements met the
criteria for hedge accounting and were designated as a cash flow hedge. In accordance with cash flow hedge accounting, the
Company recorded the loss associated with the fair value of the cash flow hedge, net of tax, as a component of accumulated other
comprehensive loss and amortizes the accumulated comprehensive loss to earnings as interest expense over the life of the 6%
Senior Notes. In 2018, 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, 2017, except for certain
natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the "normal purchases
and normal sales" exception provided in the FASB guidance for accounting for derivative instruments and hedging activities, and,
as such, were not required to be accounted for as derivatives.
Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets,
are reported at fair value which was $286.9 million and $255.7 million at December 31, 2017 and 2016, respectively. These
securities are classified as available for sale and recorded at their estimated fair value using the FASB guidance for certain
investments in debt and equity securities. The reported fair values include gross unrealized losses on marketable securities whose
impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of
these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized
loss position (in thousands):
105
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31, 2017
Less than 12 Months
12 Months or Longer
Total
Fair
Value
Unrealized
Losses
Fair
Value
Unrealized
Losses
Fair
Value
Unrealized
Losses
Description of Securities (1):
Federal Agency Mortgage Backed Securities ....... $
U.S. Government Bonds .......................................
Municipal Debt Obligations..................................
Corporate Debt Obligations ..................................
Total Debt Securities......................................
Common Stock......................................................
4,700
28,866
4,290
10,685
48,541
962
Total Temporarily Impaired Securities...... $ 49,503
$
$
____________________
(1)
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)
December 31, 2016
Less than 12 Months
12 Months or Longer
Total
Fair
Value
Unrealized
Losses
Fair
Value
Unrealized
Losses
Fair
Value
Unrealized
Losses
Description of Securities (2):
Federal Agency Mortgage Backed Securities ....... $ 11,582
31,655
U.S. Government Bonds .......................................
9,596
Municipal Debt Obligations..................................
7,971
Corporate Debt Obligations ..................................
60,804
Total Debt Securities......................................
2,760
Common Stock......................................................
22,945
Institutional Funds-International Equity ...............
Total Temporarily Impaired Securities...... $ 86,509
______________________
(2)
Includes approximately 152 securities.
$
$
(239) $
(762)
(394)
(172)
(1,567)
(167)
(110)
436
17,976
4,067
2,092
24,571
—
—
(1,844) $ 24,571
$
$
(22) $ 12,018
(835)
49,631
(372)
13,663
(172)
10,063
(1,401)
85,375
2,760
—
22,945
—
(1,401) $ 111,080
$
$
(261)
(1,597)
(766)
(344)
(2,968)
(167)
(110)
(3,245)
The Company monitors the length of time specific securities trade below its cost basis along with the amount and percentage
of the unrealized loss in determining if a decline in fair value of marketable securities below recorded cost is considered to be
other than temporary. The Company recognizes impairment losses on certain of its securities deemed to be other than temporary.
In accordance with the FASB guidance, these impairment losses are recognized in net income, and a lower cost basis is established
for these securities. In addition, the Company will research the future prospects of individual securities as necessary. The Company
does not anticipate expending monies held in trust before 2044 or a later period when decommissioning of Palo Verde begins.
For the twelve months ended December 31, 2017, 2016, and 2015, 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) $
(338)
2017
2016
2015
The reported securities also include gross unrealized gains on marketable securities which have not been recognized in the
Company’s net income. The table below presents the unrecognized gross unrealized gains and the fair value of these securities,
aggregated by investment category (in thousands):
106
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Description of Securities:
Federal Agency Mortgage Backed Securities.............................. $
U.S. Government Bonds..............................................................
Municipal Debt Obligations ........................................................
Corporate Debt Obligations.........................................................
Total Debt Securities .....................................................
Common Stock ............................................................................
Equity Mutual Funds ...................................................................
Institutional Funds-International Equity......................................
Cash and Cash Equivalents .........................................................
Total .................................................................... $
December 31, 2017
December 31, 2016
Fair
Value
Unrealized
Gains
Fair
Value
Unrealized
Gains
5,933
11,129
2,558
19,514
39,134
52,879
67,186
28,804
6,864
194,867
$
$
203
256
109
1,067
1,635
32,625
12,962
5,908
—
53,130
$
$
7,430
12,237
2,481
12,350
34,498
61,884
42,244
—
6,002
144,628
$
$
319
138
144
655
1,256
34,066
3,345
—
—
38,667
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, 2017 is as follows
(in thousands):
Total
2018
2019 through
2022
2023 through
2027
2028 and
Beyond
Federal Agency Mortgage Backed Securities $
U.S. Government Bonds ................................
Municipal Debt Obligations...........................
Corporate Debt Obligations ...........................
20,732
58,181
16,584
34,674
$
— $
5,251
511
215
$
18
27,181
7,690
16,946
$
280
11,663
7,064
7,601
20,434
14,086
1,319
9,912
The Company’s marketable securities in its decommissioning trust funds are sold from time to time and the Company uses
the specific identification basis to determine the amount to reclassify from accumulated other comprehensive income into net
income. The proceeds from the sale of these securities during the twelve months ended December 31, 2017, 2016, and 2015 and
the related effects on pre-tax income are as follows (in thousands):
2017
2016
Proceeds from sales 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 in pre-tax income .......................................................................... $
Net unrealized holding gains (losses) included in accumulated other
comprehensive income.......................................................................................... $
Net gains reclassified out of accumulated other comprehensive income .............
Net gains (losses) in other comprehensive income ....................................... $
97,037
11,773
(1,147)
—
10,626
25,275
(10,626)
14,649
$
$
$
$
$
91,268
9,212
(1,220)
(352)
7,640
8,444
(7,640)
804
$
$
$
$
$
2015
102,567
12,379
(927)
(338)
11,114
(2,906)
(11,114)
(14,020)
Fair Value Measurements. The FASB guidance requires the Company to provide expanded quantitative disclosures for
financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company's
decommissioning trust investments and investments in debt securities which are included in deferred charges and other assets on
the Balance Sheets. The Company has no liabilities that are measured at fair value on a recurring basis. The FASB guidance
establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as
follows:
•
Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial
assets utilizing Level 1 inputs include the nuclear decommissioning trust investments in active exchange-traded equity
securities, mutual funds and U.S. Treasury securities that are in a highly liquid and active market. The Institutional Funds
107
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
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 nuclear decommissioning trust investments in
fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable
market information, such as actual trade information of similar securities, adjusted for observable differences.
Level 3 - Unobservable inputs using data that is not corroborated by market data and primarily based on internal Company
analysis using models and various other analysis. Financial assets utilizing Level 3 inputs are the Company's investment
in debt securities.
The securities in the Company's decommissioning trust funds are valued using prices and other relevant information generated
by market transactions involving identical or comparable securities. The FASB guidance identifies this valuation technique as the
"market approach" with observable inputs. The Company analyzes available-for-sale securities to determine if losses are other
than temporary.
The fair value of the Company’s decommissioning trust funds and investments in debt securities at December 31, 2017
and 2016, 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,
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 ....................................
Available for sale:
Federal Agency Mortgage Backed Securities..............
U.S. Government Bonds..............................................
Municipal Debt Obligations ........................................
Corporate Debt Obligations.........................................
Subtotal, Debt Securities ......................................
Common Stock ............................................................
Equity Mutual Funds ...................................................
Institutional Funds-International Equity......................
Cash and Cash Equivalents .........................................
Total Available for Sale ........................................
$
$
$
1,735
20,732
58,181
16,584
34,674
130,171
53,841
67,186
28,804
6,864
286,866
$
$
$
— $
— $
1,735
— $
58,181
—
—
58,181
53,841
67,186
28,804
6,864
214,876
$
20,732
—
16,584
34,674
71,990
—
—
—
—
71,990
$
$
—
—
—
—
—
—
—
—
—
—
108
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Description of Securities
Trading Securities:
Fair Value as
of
December 31,
2016
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Investments in Debt Securities ............................................. $
1,421
Available for sale:
Federal Agency Mortgage Backed Securities ...................... $
U.S. Government Bonds.......................................................
Municipal Debt Obligations .................................................
Corporate Debt Obligations .................................................
Subtotal, Debt Securities...............................................
Common Stock.....................................................................
Equity Mutual Funds............................................................
Institutional Funds-International Equity ..............................
Cash and Cash Equivalents ..................................................
Total Available for Sale ................................................. $
19,448
61,868
16,144
22,413
119,873
64,644
42,244
22,945
6,002
255,708
$
$
$
— $
— $
1,421
— $
61,868
—
—
61,868
64,644
42,244
22,945
6,002
197,703
$
19,448
—
16,144
22,413
58,005
—
—
—
—
58,005
$
$
—
—
—
—
—
—
—
—
—
—
Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt 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.
1,421
314
1,735
$
$
1,543
(122)
1,421
2017
2016
There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable
inputs during the twelve month periods ending December 31, 2017 and 2016. There were no purchases, sales, issuances, and
settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending
December 31, 2017 and 2016.
109
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
P.
Supplemental Statements of Cash Flows Disclosures
Years Ended December 31,
2017
2016
2015
(In thousands)
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit
facility ............................................................................................................. $
Income tax paid, net........................................................................................
70,523
$
69,990
$
2,055
2,328
62,297
1,000
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 ......................................................................
—
(5,090)
1,171
932
27,720
4,789
1,235
—
—
(6,660)
1,567
—
(a) The Company sold its interest in Four Corners in July 2016. The sales proceeds were reduced by the settlement of other
obligations between the Company and APS and its affiliate, 4C Acquisition, LLC. See Part II, Item 8, Financial Statements
and Supplementary Data, Note E.
110
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Q.
Selected Quarterly Financial Data (Unaudited)
The following table summarizes the Company’s unaudited results of operations on a quarterly basis. The quarterly earnings
per share amounts for a year will not add to the earnings per share for that year due to the weighting of shares used in calculating
per share data.
2017 Quarters
2016 Quarters
4th (2)
3rd
2nd
1st
4th
3rd (3)
2nd
1st
Operating revenues (1) .............. $196,149
Operating income (loss) ............
20,299
105,737
Net income (loss).......................
6,500
59,684
Basic earnings per share:
(In thousands except for share data)
$297,470
$251,843
$171,335
$188,037
$323,225
$217,865
65,939
36,066
6,279
(3,989)
20,470
129,857
5,656
74,636
44,697
22,284
$157,809
(163)
(5,808)
Net income (loss) ...............
0.16
1.47
0.89
(0.10)
0.14
1.84
0.55
(0.14)
Diluted earnings per share:
Net income (loss) ...............
Dividends declared per share of
common stock............................
0.16
1.47
0.89
(0.10)
0.14
1.84
0.55
(0.14)
0.335
0.335
0.335
0.310
0.310
0.310
0.310
0.295
________________
(1) Operating revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months.
Comparisons among quarters of a year may not represent overall trends and changes in operations.
(2) 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 C.
(3) 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. See Part II, Item 8,
Financial Statements and Supplementary Data, Note C.
111
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, 2017, 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 50 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, 2017, 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 has been omitted from this Annual Report to Shareholders.
PART III and PART IV
112
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