GROWTH
2016
ANNUAL REPORT
CUSTOMER
T
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E
M
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I
In 2016, El Paso Electric Company (“EE” or the
“Company”) achieved several significant Company
milestones and celebrated a year of continued
growth and development in the region we serve.
Our successes in 2016 would not have been possible
without the more than 1,100 dedicated employees
who work hard every day to provide outstanding levels
of service to our customers in west Texas and southern
New Mexico.
Our region is fortunate to continue benefitting from
several multi-million dollar construction projects in both
the public and private sectors. During this period of
robust economic expansion, the Company continues
to provide consistently clean, safe and reliable electrical
service, all while preparing for continued customer
growth and demand.
We were very pleased to have obtained final orders
in our rate cases in Texas and New Mexico. In Texas,
which accounts for approximately 80% of our non-fuel
base revenues, we received a final order that resulted
in $40.9 million of non-fuel base revenues being
recorded in 2016. The successful completion of our rate
cases was achieved through collaboration between all
parties involved, and we look forward to continuing
to communicate openly with our communities and
stakeholders affected by changes in our rates.
In July, we completed the sale of the Company’s
ownership interest in the Four Corners Generating
Station, making us a coal-free utility. The sale of our
interest in this plant allows EE to make use of cleaner
technologies that are both more efficient and more
responsive to changes in demand. This milestone,
coupled with our efforts in expanding our renewable
portfolio, means that we have prevented 2 billion
pounds of CO2 emissions from the atmosphere,
further reducing our already low carbon footprint.
On July 14, 2016, we set another native system peak
record of 1,892 megawatts, which surpassed our 2015
record peak of 1,794 megawatts by 5.5%. Due to the
continued growth in our service territory, the Company
has set a new native peak record in 15 out of the past
16 years.
That same month, the Company completed the
Montana Power Generating Station, a critical
component in our efforts to reliably meet the region’s
increasing demand, by placing Units 3 and 4 into
commercial operation. Together with Units 1 and 2,
these four units added a total of 354 megawatts
of clean burning natural gas to our local generation
fleet, and will provide enough energy to meet the
needs of more than 160,000 homes in our growing
service territory.
In Texas, we ranked number one in reliability for
both the frequency and duration of outages. This
contributed to achieving above target customer
satisfaction and call center performance for the
year as well.
All of these successes are due to our greatest
asset – our employees. The continued partnership with
our IBEW Local Union 960, with whom we successfully
completed negotiations for a three year collective
bargaining agreement in 2016, has helped us further
our commitment to safely provide reliable power
to our region.
In 2016, our employees continued the Company’s long
tradition of community service by volunteering more
than 9,500 hours to our local communities. We are
proud to support their dedicated participation,
often in key leadership roles, in numerous organizations
that benefit the communities that we serve.
In looking ahead to further innovation and growth
in our community, the Company is excited to make
2017 a year of great strides in energy technology and
renewable energy projects. This year, we will begin our
Demand Response program, which will allow customers
to voluntarily subscribe to help lower peak demand
during the times of highest energy usage. Additionally,
we anticipate the completion of the three megawatt
Texas Community Solar program, the first of its kind in
Texas, and the five megawatt dedicated solar facility at
the Holloman Air Force Base. These renewable energy
projects will be the first large-scale solar facilities to be
owned and operated by the Company, and allow us
to realize one of the Company’s objectives of adding
affordable large scale solar to our generation mix.
We made great strides in 2016 in ensuring the continued
reliability and improvement of our power grid. With the
completion of the Montana Power Generating Station
and upgrades to existing infrastructure, EE has added
an additional $444 million of capital investment since
2015. To begin the process of recovering its most recent
investments, the Company filed a general rate case in
Texas on February 13, 2017.
We are proud of our accomplishments over the past
year, and look forward to continuing EE’s traditions of
innovation, reliability and safety as we serve our region
in 2017 and beyond.
Mary E. Kipp
Chief Executive Officer
Charles A. Yamarone
Chairman of the
Board of Directors
BOARD
OF DIRECTORS
Charles A. Yamarone
Chairman of the Board / El Paso Electric Company
Chief Corporate Governance and Compliance Officer
Houlihan Lokey, a global investment bank
Edward Escudero
Vice Chairman of the Board / El Paso Electric Company
President and Chief Executive Officer
High Desert Capital, LLC, a finance company
Catherine A. Allen
Founder, Chairman and Chief Executive Officer
The Santa Fe Group, a strategic consulting company
J. Robert Brown
Owner and President
Brownco Capital, LLC, a private investment company
OFFICERS
Mary E. Kipp
Chief Executive Officer
John R. Boomer
Senior Vice President
and General Counsel
Steven T. Buraczyk
Senior Vice President
Operations
Nathan T. Hirschi
Senior Vice President
and Chief Financial Officer
Rocky R. Miracle
Senior Vice President
Corporate Services and
Chief Compliance Officer
William A. Stiller
Senior Vice President
Public and Customer Affairs and
Chief Human Resources Officer
Robert C. Doyle
Vice President
Transmission and Distribution
and System Planning
Russell G. Gibson
Vice President
Controller
2016
BOARD OF DIRECTORS
& OFFICERS
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
Chief Executive Officer
El Paso Electric Company
Thomas V. Shockley, III
Retired Chief Executive Officer
El Paso Electric Company
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
Eduardo Gutiérrez
Vice President
Public, Government and Customer Affairs
James A. Schichtl
Vice President
Regulatory Affairs
David C. Hawkins
Vice President
System Operations, Resource
Planning and Management
Kerry B. Lore
Vice President
Customer Care
Andres R. Ramirez
Vice President
Power Generation
Guillermo Silva, Jr.
Vice President
Community Outreach
H. Wayne Soza
Vice President
Compliance and Chief Risk Officer
Richard E. Turner
Vice President
Renewables Development
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, 2016
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 is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 126-2 of the Exchange
Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES
NO
As of June 30, 2016, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,883,999,218 (based
on the closing price as quoted on the New York Stock Exchange on that date).
As of January 31, 2017, there were 40,557,679 shares of the Company’s no par value common stock outstanding.
Portions of the registrant’s definitive Proxy Statement for the 2017 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
ASU
Company
DOE
El Paso
FASB
FERC
Fort Bliss
Four Corners
GHG
HAFB
IRS
kV
kW
kWh
Las Cruces
MW
MWh
NMPRC
Net dependable generating
capability
NRC
Palo Verde
Palo Verde Participants
PNM
PUCT
RGEC
RGRT
TEP
White Sands
Arizona Public Service Company
Accounting Standards Update
El Paso Electric Company
United States Department of Energy
City of El Paso, Texas
Financial Accounting Standards Board
Federal Energy Regulatory Commission
Fort Bliss, the United States Army post next to El Paso, Texas
Four Corners Generating Station
Greenhouse gas
Holloman Air Force Base
Internal Revenue Service
Kilovolt(s)
Kilowatt(s)
Kilowatt-hour(s)
City of Las Cruces, New Mexico
Megawatt(s)
Megawatt-hour(s)
New Mexico Public Regulation Commission
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
Nuclear Regulatory Commission
Palo Verde Nuclear 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
Public Service Company of New Mexico
Public Utility Commission of Texas
Rio Grande Electric Cooperative
Rio Grande Resources Trust
Tucson Electric Power Company
White Sands Missile Range
(i)
TABLE OF CONTENTS
Item
Description
Page
PART I
1 Business .......................................................................................................................................................................
1
1A Risk Factors ................................................................................................................................................................. 17
1B Unresolved Staff Comments ........................................................................................................................................ 23
2 Properties ..................................................................................................................................................................... 23
3 Legal Proceedings ........................................................................................................................................................ 23
4 Mine Safety Disclosures .............................................................................................................................................. 23
PART II
5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ... 24
6 Selected Financial Data ................................................................................................................................................ 26
7 Management’s Discussion and Analysis of Financial Condition and Results of Operations ....................................... 27
7A Quantitative and Qualitative Disclosures About Market Risk ..................................................................................... 48
8 Financial Statements and Supplementary Data ............................................................................................................ 50
9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ....................................... 109
9A Controls and Procedures .............................................................................................................................................. 109
9B Other Information ........................................................................................................................................................ 109
PART III ................................................................................................................................................................. 109
PART IV ................................................................................................................................................................. 109
(ii)
FORWARD-LOOKING STATEMENTS
Certain matters discussed in this Annual Report on Form 10-K, other than statements of historical fact, are "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E
of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Forward-looking statements often include words like
we "believe", "anticipate", "target", "project", "expect", "predict", "pro forma", "estimate", "intend", "will", "is designed to", "plan"
and words of similar meaning, or are indicated by the Company's discussion of strategies or trends. Forward-looking statements
describe the Company's future plans, objectives, expectations or goals. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, no assurances can be given that these expectations will prove to be
correct. Such statements address future events and conditions and include, but are not limited to:
•
•
•
•
•
•
•
•
•
•
•
•
capital expenditures,
earnings,
liquidity and capital resources,
ratemaking/regulatory matters,
litigation,
accounting matters,
possible corporate restructurings, acquisitions and dispositions,
compliance with debt and other restrictive covenants,
interest rates and dividends,
environmental matters,
nuclear operations, and
the overall economy of our service area.
These forward-looking statements are based on assumptions and analyses in light of the Company's experience and perception
of historical trends, current conditions, expected future developments and other factors the Company believes were appropriate
in the circumstances when the statements were made. Forward-looking statements by their nature involve substantial risks and
uncertainties that could significantly impact expected results, and actual future results could differ materially from those described
in such statements. While it is not possible to identify all factors, the Company continues to face many risks and uncertainties.
Factors that would cause or contribute to such differences include, but are not limited to:
•
•
•
•
•
•
•
•
•
•
•
actions of the Company's regulators,
the Company's ability to fully and timely recover its costs and earn a reasonable rate of return on its invested
capital through the rates that it is permitted to charge,
rates, cost recovery mechanisms and other regulatory matters including the ability to recover fuel costs on
a timely basis,
the ability of the Company's operating partners to maintain plant operations and manage operation and
maintenance costs at the Palo Verde Nuclear Generating Station ("Palo Verde"), including costs to comply
with any new or expanded regulatory or environmental requirements,
reductions in output at generation plants operated by the Company,
the size of the Company's construction program and its ability to complete construction on budget and on
time,
the Company's reliance on significant customers,
the credit worthiness of the Company's customers,
unscheduled outages of generating units including outages at Palo Verde,
changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging
competing services and technologies, including distributed generation,
individual customer groups, including distributed generation customers, may not pay their full cost of
service, and other customers may or may not be required to pay the difference,
(iii)
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
changes in, and the assumptions used for, pension and other post-retirement and post-employment benefit
liability calculations, as well as actual and assumed investment returns on pension plan and other post-
retirement plan assets,
the impact of changing cost escalation and other assumptions on the Company's nuclear decommissioning
liability for Palo Verde, as well as actual and assumed investment returns on decommissioning trust fund
assets,
disruptions in the Company's transmission system, and in particular the lines that deliver power from its
remote generating facilities,
electric utility deregulation or re-regulation,
regulated and competitive markets,
ongoing municipal, state and federal activities,
cuts in military spending or shutdowns of the federal government that reduce demand for the Company's
services from military and governmental customers,
political, legislative, judicial and regulatory developments,
homeland security considerations, including those associated with the U.S./Mexico border region and the
energy industry,
changes in environmental laws and regulations and the enforcement or interpretation thereof, including
those related to air, water or greenhouse gas ("GHG") emissions or other environmental matters,
economic and capital market conditions,
changes in accounting requirements and other accounting matters,
changing weather trends and the impact of severe weather conditions,
possible physical or cyber attacks, intrusions or other catastrophic events,
the impact of lawsuits filed against the Company,
the impact of changes in interest rates,
Texas, New Mexico and electric industry utility service reliability standards,
coal, uranium, natural gas, oil and wholesale electricity prices and availability,
possible income tax and interest payments as a result of audit adjustments proposed by the Internal Revenue
Service ("IRS") or state taxing authorities,
the impact of U.S. health care reform legislation,
loss of key personnel, the Company's ability to recruit and retain qualified employees and the Company's
ability to successfully implement succession planning, and
other circumstances affecting anticipated operations, sales and costs.
These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is
included in this document under the headings "Risk Factors" and "Management’s Discussion and Analysis of Financial Condition
and Results of Operations –Summary of Critical Accounting Policies and Estimates" and "Management’s Discussion and Analysis
of Financial Condition and Results of Operations –Liquidity and Capital Resources." This Annual Report on Form 10-K should
be read in its entirety. Management cautions against putting undue reliance on forward-looking statements or projecting any future
results based on such statements or present or prior earnings levels. Any forward-looking statement speaks only as of the date
such statement was made, and the Company is not obligated to update any forward-looking statement to reflect events or
circumstances after the date on which such statement was made, except as required by applicable laws or regulations.
(iv)
Item 1.
Business
PART I
General
El Paso Electric Company (the "Company") is a public utility engaged in the generation, transmission and distribution of
electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a
full requirements wholesale customer in Texas. The Company owns or has significant ownership interests in several electrical
generating facilities providing it with a net dependable generating capability of approximately 2,080 MW. For the year ended
December 31, 2016, the Company’s energy sources consisted of approximately 49% nuclear fuel, 34% natural gas, 2% coal, 15%
purchased power and less than 1% generated by Company-owned solar photovoltaic panels. The Company continues to expand
its portfolio of renewable energy sources, particularly solar photovoltaic generation. As of December 31, 2016, the Company had
power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources – Purchased Power").
The Company serves approximately 411,100 residential, commercial, industrial, public authority and wholesale customers.
The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing
approximately 64% and 11%, respectively, of the Company’s retail revenues for the year ended December 31, 2016). In addition,
the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public
authority and other large retail customers of the Company include United States military installations, such as Fort Bliss in Texas
and White Sands Missile Range ("White Sands") and Holloman Air Force Base ("HAFB") in New Mexico, an oil refinery, several
medical centers, two large universities and a steel production facility.
The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone:
915-543-5711). The Company was incorporated in Texas in 1901. As of January 31, 2017, the Company had approximately
1,100 employees, 38% of whom are covered by a collective bargaining agreement.
The Company makes available free of charge through its website, www.epelectric.com, its Annual Report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statement and all amendments to those reports as soon as
reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission
("SEC"). In addition, copies of this Annual Report on Form 10-K will be made available free of charge upon written request. The
SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that
file electronically with the SEC. The address of that site is www.sec.gov. The information on the Company's website is not
incorporated by reference into this Annual Report on Form 10-K.
As of December 31, 2016, the Company’s net dependable generating capability of approximately 2,080 MW consists of
the following:
Facilities
Station
Newman Power Station
Palo Verde
Rio Grande Power Station
Montana Power Station (Units 1, 2, 3
and 4)
Copper Power Station
Renewables
Total
Primary Fuel
Type
Natural Gas
Nuclear
Natural Gas
Natural Gas
Natural Gas
Solar
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
1
2,080
1
Palo Verde
The Company owns an interest, along with six other utilities, in the three nuclear generating units and common facilities
("Common Facilities") at Palo Verde. Arizona Public Service Company ("APS") serves as operating agent for Palo Verde, and
under the Arizona Nuclear Power Project Participation Agreement ("ANPP Participation Agreement"), the Company has limited
ability to influence operations and costs at Palo Verde.
• Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license
from the Nuclear Regulatory Commission ("NRC"). The NRC issued full power operating licenses for Unit 1
in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and issued renewed operating licenses for each
of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and
November 2047, respectively.
• Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its
share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities,
through the term of their respective operating licenses. In 2013, the Palo Verde Participants approved the 2013
Palo Verde decommissioning study (the "2013 Study"), which estimated that the Company must fund
approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs. At
December 31, 2016, the Company's decommissioning trust fund had a balance of $255.7 million. Although the
2013 Study was based on the latest available information, there can be no assurance that decommissioning cost
estimates attributable to the Company will not increase in the future or that regulatory requirements will not
change. A 2016 Palo Verde decommissioning study is underway and is expected to be finalized in the second
quarter of 2017 at which time the Company will record its effects.
•
Spent Fuel Storage. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the
United States Department of Energy ("DOE") is legally obligated to accept and dispose of all spent nuclear fuel
and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations
are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard
Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On
December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach of
contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to
accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On
August 18, 2014, APS and the DOE entered into a settlement agreement stipulating to a dismissal of the lawsuit
and payment of $57.4 million by the DOE to the Palo Verde Participants for certain specified costs incurred by
Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received
approximately $9.1 million, representing its share of the award, of which $7.9 million was refunded to customers
through the applicable fuel adjustment clauses. On October 31, 2014, APS, acting on behalf of itself and the
Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear
fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was $42.0
million. On June 1, 2015, the Company received approximately $6.6 million, representing its share of the award,
of which $5.8 million was credited to customers through the applicable fuel adjustment clauses in March 2015.
After June 2015, APS will file annual claims for the period July 1 of the then-previous year to June 30 of the
then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through
June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. Funds related to this claim
were received in the first quarter of 2016. The Company's share of this claim is approximately $1.9 million, of
which $1.6 million was credited to customers through the applicable fuel adjustment clauses in March 2016.
On October 31, 2016 APS filed an $11.3 million claim for the period July 1, 2015 through June 30, 2016. The
Company's share of this claim is approximately$1.8 million. On February 1, 2017, the DOE notified APS of the
approval of the claim. Any reimbursement is anticipated to be received in the second quarter of 2017, and the
majority of the award received by the Company will be credited to customers through applicable fuel adjustment
clauses.
• DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal
obligations by designing, licensing, constructing and operating a permanent geologic repository in Yucca
Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain
construction authorization application that was pending before the NRC. Several interested parties have
intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the
courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions
around the country challenging the DOE's authority to withdraw the Yucca Mountain construction authorization
2
application and NRC’s cessation of its review of the Yucca Mountain construction authorization application.
The cases have been consolidated into one matter at the U.S. Court of Appeals for the District of Columbia
Circuit (the "D.C. Circuit"). In August 2013, the D.C. Circuit ordered the NRC to resume its review of the
application with available appropriated funds.
On October 16, 2014, the NRC issued Volume 3 of the safety evaluation report developed as part of the Yucca
Mountain construction authorization application. This volume addresses repository safety after permanent
closure, and the issuance of Volume 3 is a key milestone in the Yucca Mountain licensing process. Volume 3
contains the NRC staff’s finding that the DOE’s repository design meets the requirements that apply after the
repository is permanently closed, including but not limited to the post-closure performance objectives in the
NRC’s regulations.
On December 18, 2014, the NRC issued Volume 4 of the safety evaluation report developed as part of the Yucca
Mountain construction authorization application. This volume covers administrative and programmatic
requirements for the repository. It documents the NRC staff’s evaluation of whether the DOE’s research and
development and performance confirmation programs, as well as other administrative controls and systems,
meet applicable NRC requirements. Volume 4 contains the NRC staff’s finding that most administrative and
programmatic requirements in NRC regulations are met, except for certain requirements relating to ownership
of land and water rights.
Publication of Volumes 3 and 4 does not signal whether or when the NRC might authorize construction of the
repository. The Company cannot predict when spent fuel shipments to the DOE will commence.
• Waste Confidence. On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and
environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high
level nuclear waste and spent nuclear fuel. The petitioners challenged the NRC’s 2010 update to the agency’s
Waste Confidence Decision and temporary storage rule ("Waste Confidence Decision").
The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal
action, which, consistent with the National Environmental Policy Act ("NEPA"), requires either an environmental
impact statement or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that
the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded
the 2010 Waste Confidence Decision update for further action consistent with NEPA.
On September 6, 2012, the NRC Commissioners issued a directive to the NRC staff to proceed directly with
development of a generic environmental impact statement to support an updated Waste Confidence Decision.
The NRC Commissioners also directed the NRC staff to establish a schedule to publish a final rule and
environmental impact study within 24 months of September 6, 2012.
In September 2013, the NRC issued its draft Generic Environmental Impact Statement ("GEIS") to support an
updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental
effects of continued storage of spent nuclear fuel. The continued storage rule adopted the findings of the GEIS
regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period
of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for
individual licenses. Although Palo Verde has not been involved in any licensing actions affected by the D.C.
Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power
plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The final
Continued Storage Rule was subject to continuing legal challenges before the NRC and the Court of Appeals.
In June 2016, the D.C. Circuit issued its final decision, rejecting all remaining legal challenges to the Continue
Storage Rule. On August 8, 2016, the D.C. Circuit denied a petition for rehearing.
Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation ("ISFSI") to store all
of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December
2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will
be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding
the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will
evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the
fuel that will be irradiated during the period of extended operation.
The One-Mill Fee. In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear
Energy Institute challenged the DOE’s 2010 determination of the adequacy of the one tenth of a cent per kWh
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 12, 2014, APS
was notified by the DOE that, effective May 16, 2014, the one-mill fee would be suspended. Electricity generated
at Palo Verde and sold prior to May 16, 2014 remained subject to the one-mill fee.
• NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. The NRC
regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The
NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the
agency to arrive at objective conclusions about a licensee's safety performance. Following the March 11, 2011
earthquake and tsunami in Japan, the NRC established a task force to conduct a systematic and methodical
review of NRC processes and regulations to determine whether the agency should make additional improvements
to its regulatory system. On March 12, 2012, the NRC issued the first regulatory requirements based on the
recommendations of the NRC's Near Term Task Force. With respect to Palo Verde, the NRC issued two orders
requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting
in the loss of power at plants and (2) enhancement of spent fuel pool instrumentation.
The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements.
Palo Verde has met the NRC's imposed deadlines for the installation of equipment to address these requirements.
Palo Verde has spent approximately $125.0 million (the Company's share is $19.7 million) on capital
enhancements related to these requirements as of December 31, 2016.
• Liability and Insurance Matters. The Palo Verde Participants have insurance for public liability resulting from
nuclear energy hazards, covered by primary liability insurance provided by commercial insurance carriers and
an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs
exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective
premium adjustments on a per incident basis up to $60.4 million, with an annual payment limitation of
approximately $9.0 million. The Palo Verde Participants also maintain $2.75 billion of "all risk" nuclear property
insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered
incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage
limit is $2.25 billion. In addition, the Company has secured insurance against portions of any increased cost of
generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo
Verde.
Fossil-Fueled Plants
The Newman Power Station ("Newman") consists of three conventional steam-electric generating units and two combined
cycle generating units. The station operates primarily on natural gas but the conventional steam-electric generating units can also
operate on fuel oil.
The Company's Rio Grande Power Station ("Rio Grande") consists of three conventional steam-electric generating units
and one aeroderivative unit that operate on natural gas.
The Company's Montana Power Station ("MPS") consists of four aeroderivative generating units which operate on natural
gas. The units can also operate on fuel oil.
The Company's Copper Power Station ("Copper") consists of a natural gas combustion turbine used primarily to meet peak
demand.
The Company owned a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners"). The Company
shared power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other
Four Corners participants. On February 17, 2015, the Company and APS entered into an asset purchase agreement (the "Purchase
and Sale Agreement") providing for the sale of the Company’s interests in Four Corners to APS. Four Corners continued to provide
energy to serve the Company's native load up to the closing date of the sale on July 6, 2016. Also on July 6, 2016, prior to the
4
closing of the transaction, the Company and APS entered into an amendment to the Purchase and Sale Agreement pursuant to
which APS assigned its right, title and interest in the Purchase and Sale Agreement to its affiliate 4C Acquisition, LLC ("APS's
affiliate"), and Pinnacle West Capital Corporation, the parent company of APS and APS's affiliate ("Pinnacle West"), guaranteed
APS's affiliate's obligations under the Purchase and Sale Agreement. The sales price was $32.0 million, which was based on the
net book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5
million, respectively, to reflect the assumption by APS's affiliate of the Company's obligation to pay for future plant
decommissioning and mine reclamation expenses. The sales price was also adjusted downward by approximately $1.3 million for
estimated closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing, the Company received
approximately $4.2 million in cash, subject to post-closing adjustments. No significant gain or loss was recorded after the closing
date. APS's affiliate assumed responsibility for all Four Corners capital expenditures made after July 6, 2016, which assumption
is guaranteed by Pinnacle West. In addition, APS's affiliate will indemnify the Company against certain liabilities and costs related
to the future operation of Four Corners, which indemnification is guaranteed by Pinnacle West. See Part II, Item 8, "Financial
Statements and Supplementary Data, Note C and Note E of Notes to Financial Statements" for further discussions.
Wind and Solar Photovoltaic Facilities
The Company’s Hueco Mountain Wind Ranch consisted of two wind turbines with a total capacity of 1.32 MW. The two
wind turbines were decommissioned in June 2016. The Company also owns six solar photovoltaic facilities with a total capacity
of 0.2 MW.
Transmission and Distribution Lines and Agreements
The Company owns, or has significant ownership interests in, four 345 kV transmission lines in New Mexico and Arizona
and three 500 kV lines in Arizona. These lines enable the Company to deliver its energy entitlements from its remote generation
sources at Palo Verde and, prior to July 6, 2016, Four Corners, to its service area (pursuant to various transmission and power
exchange agreements to which the Company is a party). The Company also owns the transmission and distribution network within
its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities.
Pursuant to standards established by the North American Electric Reliability Corporation and the Western Electricity Coordinating
Council, the Company operates its transmission system in a way that allows it to maintain system integrity in the event that any
one of these transmission lines is out of service.
In addition to the transmission and distribution lines within our service territory, the Company's transmission network and
associated substations include the following:
Line
Springerville-Macho Springs-Luna-Diablo Line (1)
West Mesa-Arroyo Line (2)
Greenlee-Hidalgo-Luna-Newman Line (3)
Length (miles)
310
202
Voltage (kV)
345
345
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
345
345
345
345
500
500
Company
Ownership
Interest
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.
Air Emissions. The U.S. Clean Air Act ("CAA"), associated regulations and comparable state and local laws and regulations
relating to air emissions impose, among other obligations, limitations on pollutants generated during the operations of the Company's
facilities and assets, including sulfur dioxide ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury.
Cross State Air Pollution Rule. The U.S. Environmental Protection Agency (the "EPA") promulgated the Cross-State Air
Pollution Rule ("CSAPR") in August 2011, which involves requirements to limit emissions of NOx and SO2 from certain of the
Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions. CSAPR was intended
to replace the EPA's 2005 Clean Air Interstate Rule ("CAIR"). The U.S. Court of Appeals for the District of Columbia Circuit
("D.C. Circuit") vacated CSAPR in August 2012 and allowed CAIR to stand until the EPA issued a proper replacement. On April
29, 2014, the U.S. Supreme Court reversed and upheld CSAPR, remanding certain portions of CSAPR to the D.C. Circuit for
further consideration. On July 28, 2015, the D.C. Circuit ruled that the EPA's emissions budgets for 13 states, including Texas,
are invalid but left the rule in place on remand. On October 26, 2016, the EPA published its final CSAPR Update Rule with an
effective date of December 27, 2016. While we are unable to determine the full impact of this rule at this time, the Company
believes it is currently positioned to comply with CSAPR.
National Ambient Air Quality Standards ("NAAQS"). Under the CAA, the EPA sets NAAQS for six criteria pollutants
considered harmful to public health and the environment, including PM, NOx, carbon monoxide ("CO"), ozone and SO2. NAAQS
must be reviewed by the EPA at five-year intervals. In 2010, the EPA tightened the NAAQS for both nitrogen dioxide ("NO2")
and SO2. The EPA is considering a 1-hour secondary NAAQS for NO2 and SO2. In January 2013, the EPA tightened the NAAQS
for fine PM. On October 1, 2015, following on its November 2014 proposal, EPA released a final rule tightening the primary and
secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion ("ppb") to 70 ppb. Ozone is the
main component of smog. While not directly emitted into the air, it forms from precursors, including NOx and volatile organic
compounds, in combination with sunlight. The EPA is scheduled to make attainment/nonattainment designations for the revised
ozone standards by October 1, 2017. While it is currently unknown how the areas in which we operate will be designated, for
nonattainment areas classified as "Moderate" and above, states, and any tribes that choose to do so, are expected to be required to
complete development of implementation plans in the 2020-2021 timeframe. Most nonattainment areas are expected to have until
2020 or 2023 to meet the primary (health) standard, with the exact attainment date varying based on the ozone level in the area.
The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company
is required to install additional equipment to control emissions at its facilities, the NAAQS, individually or in the aggregate, could
have a material impact on its operations and financial results.
Other Laws and Regulations and Risks. The Company sold its interest in Four Corners to APS's affiliate on July 6, 2016 at
the expiration of the 50-year participation agreement. As of the closing date of the sale, the Company’s environmental liabilities
associated with Four Corners were limited to conditions that existed at the time of the sale and further limited to the portion thereof
for which the Company would have been financially responsible if Four Corners had fully ceased operation on July 6, 2016. As
the Company no longer owns any coal-fired generation as a result of the sale, it believes it is not responsible for a significant
portion of the compliance or ongoing operational costs associated with the Mercury and Air Toxics Standards ("MATS"), the Coal
Combustion Residue ("CCR") Rule, or the revised Wastewater Effluent Limitation Guidelines ("ELG"), which had been identified
in previous filings that the Company has made with the SEC. Pursuant to the terms of the Purchase and Sale Agreement, neither
APS's affiliate nor APS assumed the Company's pre-closing obligations under environmental laws with respect to its interest in
Four Corners. Similar to other former owners of real property, the Company may be subject to certain future claims under
environmental laws and regulations as former owner of Four Corners. The extent of such claims, if any, cannot be predicted with
certainty.
Climate Change. In recent years, there has been increasing public debate regarding the potential impact on global climate
change. There has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of GHG and possible
means for their regulation. In addition, efforts have been made and continue to be made in the international community toward
the adoption of international treaties or protocols that would address global climate change issues. Most recently, in April 2016
6
the United States signed the Paris Agreement, which requires countries to review and "represent a progression" in their intended
nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020.
The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting GHG
emissions, including carbon dioxide. In particular, the U.S. Congress has considered legislation to restrict or regulate GHG
emissions. In the past few years, the EPA began using the CAA to regulate carbon dioxide and other GHG emissions, such as the
2009 GHG Reporting Rule and the EPA’s sulfur hexafluoride ("SF6") reporting rule, both of which apply to the Company, as well
as the EPA’s 2010 actions to impose permitting requirements on new and modified sources of GHG emissions. In October 2015,
the EPA published a final rule establishing new source performance standards ("NSPS") limiting CO2 emissions from new, modified
and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to
regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected
units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean
Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions
performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February
9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. On September 27, 2016, the case
against the CPP was heard in the United States Court of Appeals for the District of Columbia Circuit. We cannot at this time
determine the impact of the CPP and related rules and legal challenges may have on our financial position, results of operations
or cash flows.
While a significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes
that its GHG emissions are low relative to electric power companies who rely more on coal-fired generation, current and future
legislation and regulation of GHG or any future related litigation could impose significant costs and/or operating restrictions on
the Company, reduce demand for the power the Company generates, and/or require the Company to purchase rights to emit GHG,
any of which could be material to the Company's business, reputation, financial condition or results of operations.
Climate change also has potential physical effects that could be relevant to the Company's business. In particular, some
studies suggest that climate change could affect the Company's service area by causing higher temperatures, less winter precipitation
and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power
in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability
of Company equipment. The Company believes that material effects on the Company's business or results of operations may result
from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented
by governmental authorities, or both. Given the very significant remaining uncertainties regarding whether and how these issues
will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible
to meaningfully quantify the costs of these potential impacts at present.
Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the
EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The
allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the
controls necessary under the CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under
Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. District
Court for New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S.
District Court for New Mexico entered the CAA Settlement Agreement. The agreement imposes a total civil penalty payable by
the co-owners of Four Corners collectively in the amount of $1.5 million, and it requires the co-owners to pay $6.7 million for
environmental mitigation projects. At December 31, 2016, the Company has accrued its remaining unpaid share of approximately
$0.2 million related to this matter.
Construction Program
Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating
the transmission and distribution systems, and the cost of capital improvements and replacements at Palo Verde. Studies indicate
that the Company will need additional power generation resources to meet increasing load requirements on its system and to
replace retiring plants and terminated purchased power agreements, the costs of which are included in the table below.
7
The Company’s estimated cash construction costs for 2017 through 2021 are approximately $1.1 billion. Actual costs may
vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed
conditions.
By Year (1)(2)
(estimates in millions)
By Function
(estimates in millions)
2017
2018
2019
2020
2021
Total
$
$
215
185
203
240
242
1,085
Production (1)(2)
Transmission
Distribution
General
$
492
131
349
113
Total
$
1,085
__________________________
(1) Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel."
(2) Estimated production costs consist of:
a.
$273 million for new generating capacity, including:
i.
ii.
$253 million of construction costs from 2018 through 2021 for a 320 MW generating resource
scheduled for completion in 2023.
$20 million for two utility-scale solar energy generating facilities which would have a combined
maximum capacity of up to 8 MW.
b.
$219 million of other generation costs, including $191 million for Palo Verde.
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
2016
2015
(percentage of total kWh energy mix)
2014
49%
34%
2%
15%
100%
47%
34%
6%
13%
100%
47%
35%
5%
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 and conversion services through 2018 and 45% of its requirements in 2019-2025. The participants have
also contracted for 100% of Palo Verde's enrichment services through 2020, 20% of its enrichment services for 2021-2026 and all
of Palo Verde's fuel assembly fabrication services through 2024.
Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust
("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. RGRT has $95 million aggregate
principal amount borrowed in the form of senior notes, of which $50 million will mature in August 2017. The Company expects
to repay the $50 million of senior notes upon maturity with borrowings under the Company’s revolving credit facility (the "RCF")
or refinance them. The Company guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing
requirements of RGRT are met with a combination of the senior notes and short-term borrowings under the RCF.
Natural Gas
The Company manages its natural gas requirements through a combination of a long-term (greater than a year) supply
contract, several medium-term (greater than a month but less than one year) supply contracts and spot or short-term (daily to a
month) market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. Medium-
term and spot agreements are either fixed priced and/or index priced depending on the market. In 2016, the Company’s natural
gas requirements at Newman, Rio Grande and MPS were met with short-term, medium-term and long-term natural gas purchases
from various suppliers, and this practice is expected to continue in 2017. Interstate gas is delivered under a base firm transportation
contract. The Company has expanded its firm interstate transportation contract to include MPS. The Company anticipates it will
continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for Newman, Rio Grande
and MPS. The Company will continue to evaluate the availability of short-term natural gas supplies versus medium and long-term
supplies to maintain a reliable and economical supply for its local generating stations.
Natural gas for Newman and Copper is also supplied pursuant to a long-term intrastate natural gas contract that became
effective October 1, 2009 and continues through 2017.
9
Purchased Power
To supplement its own generation and operating reserve requirements, and to meet required renewable portfolio standards,
the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the
Company’s resource needs, the economics of the transactions and specific renewable portfolio requirements.
The Company has a firm 100 MW Power Purchase and Sale Agreement (the "Power Purchase and Sale Agreement") with
Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport"), pursuant to which Freeport will deliver energy to the
Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New
Mexico) and the Company will deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to the
contracted MW amount at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement.
The Power Purchase and Sale Agreement was approved by the Federal Energy Regulatory Commission ("FERC") and will continue
through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power
Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold thereunder. The parties
have agreed to increase the amount up to 125 MW through December 2018.
The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements.
Specifically, the Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar
photovoltaic project located in southern New Mexico, which began commercial operation in July 2011. In June 2015, the Company
entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement photovoltaic
modules. The Company also entered into a 20-year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all
of the output of a 20 MW solar photovoltaic plant built in southern New Mexico, which began commercial operation in August
2011. In addition, the Company has 25-year purchase power agreements to purchase all of the output of two additional solar
photovoltaic projects located in southern New Mexico, SunE EPE1, LLC (10 MW) and SunE EPE2, LLC (12 MW), which began
commercial operation in June 2012 and May 2012, respectively.
Furthermore, the Company has a 20-year purchase power agreement with Macho Springs Solar, LLC to purchase the entire
generation output delivered from the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico
which began commercial operation in May 2014. Finally, the Company has a 30-year purchase power agreement with Newman
Solar LLC to purchase the total output, which is approximately 10 MW, from a solar photovoltaic generation plant on land subleased
from the Company in proximity to Newman. This solar project began commercial operation in December 2014.
Other purchases of shorter duration were made during 2016 to supplement the Company's generation resources during planned
and unplanned outages, for economic reasons and to supply off-system sales.
10
Operating Statistics
Years Ended December 31,
2015
2014
2016
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
Number of customers (end of year) (1):
Total operating revenues
Residential
Commercial and industrial, small
Commercial and industrial, large
Other
Total
Average annual kWh use per residential customer
Energy supplied, net, kWh (in thousands):
Generated
Purchased and interchanged
Total
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
Native system:
Peak load, kW
Net dependable generating capability for peak, kW
Total system:
Peak load, kW (2)
Net dependable generating capability for peak, kW
$
$
$
$
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
234,371
185,388
39,239
92,066
551,064
2,277
553,341
161,052
3,110
71,614
235,776
74,716
21,117
2,147
97,980
30,428
917,525
353,885
40,038
49
5,017
398,989
7,496
8,820,006
1,552,251
10,372,257
9,585,089
1,390,946
10,976,035
9,477,129
1,390,490
10,867,619
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
2,640,535
2,357,846
1,064,475
1,562,784
7,625,640
61,729
2,609,769
2,671,498
10,297,138
570,481
10,867,619
1,766,000
1,879,000
1,953,000
1,879,000
___________________________
(1)
(2)
The number of retail customers presented is based on the number of service locations.
Includes spot sales and net losses of 135,000 kW, 198,000 kW and 187,000 kW for 2016, 2015 and 2014, 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 (the "2015 Texas Retail Rate Case").
On July 21, 2016, the parties to PUCT Docket No. 44941 filed the Joint Motion to Implement Uncontested Amended and
Restated Stipulation and Agreement which was unopposed by the parties (the "Unopposed Settlement"). On August 25, 2016, the
PUCT approved the Unopposed Settlement and issued its final order in Docket No. 44941 (the "PUCT Final Order"), as proposed.
The PUCT Final Order provided for: (i) an annual non-fuel base rate increase, lower annual depreciation expense, a revised return
on equity for AFUDC purposes, and the inclusion of substantially all new plant in service in rate base; (ii) an additional annual
non-fuel base rate increase of $3.7 million related to Four Corners costs, which will be collected through a surcharge terminating
on July 12, 2017; (iii) removing the separate rate treatment for residential customers with solar systems that the Company had
proposed in its August 10, 2015 filing; (iv) allowing the Company to recover $3.1 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 PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the
cumulative effect of the PUCT Final Order which related back to January 12, 2016. The effects of the PUCT Final Order on
operating results for the year ended December 31, 2016 increased operating revenues by $42.4 million, decreased depreciation
expense by $10.3 million and decreased other expenses, net by approximately $2.7 million for an aggregate increase in income
before income taxes of $50.0 million and an increase in net income of $27.3 million.
2017 Texas Retail Rate Case Filing. On February 13, 2017, the Company filed with the City of El Paso, other municipalities
incorporated in the Company's Texas service territory and the PUCT in Docket No.46831, a request for an increase in non-fuel
base revenues of approximately $42.5 million. The Company invoked its statutory right to have its new rates relate back for
consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed
will be surcharged or refunded to customers after the PUCT's final order in Docket No. 46831. The PUCT has the authority to
require the Company to surcharge or refund such difference over a period not to exceed 18 months. The Company cannot predict
the outcome or the timing of this rate case at this time.
Energy Efficiency Cost Recovery Factor. On May 1, 2015, the Company filed its annual application to establish its energy
efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and a true-up to prior year actual
costs, the Company requested approval of a $1.0 million bonus for the 2014 energy efficiency program results in accordance with
PUCT rules. This case was assigned PUCT Docket No. 44677. A stipulation and settlement agreement was filed September 24,
2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT included a performance
bonus of $1.0 million. The Company recorded the performance bonus in operating revenues in the fourth quarter of 2015.
On April 29, 2016, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2017.
In addition to projected energy efficiency costs for 2017 and true-up to prior year actual costs, the Company requested approval
of a $0.7 million bonus for the 2015 energy efficiency program results in accordance with PUCT rules. This case was assigned
PUCT Docket No. 45885. Parties in the proceeding, including PUCT staff and the City of El Paso, filed a settlement in the case
that approved the Company's proposal with a reduction to the 2015 program bonus of $0.2 million. The PUCT approved the
settlement on October 28, 2016. The settlement approved by the PUCT included a performance bonus of $0.5 million which was
recorded in operating revenues in the third quarter of 2016.
12
Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered
from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows
the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon
the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires
the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount
and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to
surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery
to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the
previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT
in fuel reconciliation proceedings.
On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor
by approximately 24% to reflect reduced fuel expenses primarily related to a reduction in the price of natural gas used to generate
power. The over-recovered balance was below the PUCT's materiality threshold. The reduction in the fixed fuel factor was effective
on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015.
On November 30, 2016, the Company filed a request, which was assigned PUCT Docket No. 46610, to increase its fixed
fuel factor by 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 December 31, 2016, the Company had under-recovered fuel costs in the amount of $11.1
million for the Texas jurisdiction.
Fuel Reconciliation Proceeding. On September 27, 2016, the Company filed an application with the PUCT, designated as
PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of
April 1, 2013 through March 31, 2016. A procedural schedule has been adopted with hearings in April 2017. As of December 31,
2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $114.4
million. The Company cannot predict the outcome or the timing of this matter.
Montana Power Station Approvals. The Company received Certificate of Convenience and Necessity ("CCN") approval
from the PUCT to construct four natural gas fired generating units at MPS in El Paso County, Texas. The Company also obtained
air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the EPA. MPS Units 1 and 2 and associated
transmission lines and common facilities were completed and placed into service in March 2015. MPS Units 3 and 4 were completed
and placed into service on May 3, 2016 and September 15, 2016, respectively.
Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program that
includes the construction and ownership of a 3 MW solar photovoltaic system located at MPS. Participation will be on a voluntary
basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT
Docket No. 44800. The Company filed a settlement agreement among all parties on July 1, 2016 approving the program, and the
PUCT approved the settlement agreement and program on September 1, 2016. The Company expects completion of the solar
facility and commencement of the program in the second quarter of 2017.
Four Corners. On February 17, 2015, the Company and 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.
On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and
certain rate and accounting findings related to the Purchase and Sale Agreement. This case was assigned PUCT Docket No. 44805.
Subsequent to the filing of the application, the case has been subject to numerous procedural matters, including a March 23, 2016
order in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the
requested rate and accounting findings, including mine reclamation costs, in a rate case proceeding. On September 1, 2016, a
motion by parties in the proceeding to suspend the procedural schedule in order to pursue settlement was approved, and the parties
are engaged in settlement discussions.
At December 31, 2016, the regulatory asset associated with the Four Corners mine reclamation costs for the Company's
Texas jurisdiction was approximately $7.3 million. The Company currently continues to recover its mine reclamation costs in
Texas under previous orders and decisions of the PUCT. If any future determinations made by the Company's regulators result in
changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes
would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions.
13
Other Required Approvals. The Company has obtained other required approvals for tariffs and approvals required by the
Public Utility Regulatory Act (the "PURA") and the PUCT.
New Mexico Regulatory Matters
2015 New Mexico Rate Case Filing. On May 11, 2015, the Company filed a request with the NMPRC, in Case No. 15-00127-
UT, for an annual increase in non-fuel base rates. On June 8, 2016, the NMPRC issued its final order in Case No. 15-00127-UT
(the "NMPRC Final Order") which approved an annual increase in non-fuel base rates of approximately $0.6 million, an increase
of approximately $0.5 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.
2017 New Mexico Rate Case Filing. NMPRC Case No. 15-00109-UT requires the Company to make a rate filing in New
Mexico in the second quarter of 2017 using a historical test year ended December 31, 2016.
Fuel and Purchased Power Costs. On January 8, 2014, the NMPRC approved the continuation of the Fuel and Purchased
Power Cost Adjustment Clause (the "FPPCAC") without modification in NMPRC Case No. 13-00380-UT. Historically, fuel and
purchased power costs were recovered through base rates and a FPPCAC that accounts for changes in the costs of fuel relative to
the amount included in base rates. Effective July 1, 2016, with the implementation of the final order in Case No. 15-00127-UT,
fuel and purchased power costs are no longer recovered through base rates but are recovered through the FPPCAC. Fuel and
purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second
succeeding month. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the
FPPCAC as purchased power using a proxy market price approved in Case No. 13-00380-UT. The Company's request to reconcile
its fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in Case No. 15-00127-
UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2016 that
total approximately $114.6 million. At December 31, 2016, the Company had a net fuel over-recovery balance of $0.2 million in
New Mexico.
Montana Power Station Approvals. The Company received CCNs from the NMPRC to construct four units at MPS and the
associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the EPA. A final order in
NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and
associated transmission lines and common facilities were completed and placed into service in March 2015. MPS Units 3 and 4
were completed and placed into service on May 3, 2016 and September 15, 2016, respectively.
Four Corners. On June 15, 2016, in NMPRC Case No. 15-00109-UT, the NMPRC issued its final order approving the
Company's sale and abandonment of its ownership interest in Four Corners to APS pursuant to a February 17, 2015 Purchase and
Sale Agreement between the Company and APS. See Part II, Item 8, "Financial Statements and Supplementary Data, Note E of
Notes to Financial Statements" for further details on the sale of Four Corners.
5 MW HAFB Facility CCN. On October 7, 2015, in NMPRC Case No. 15-00185-UT, the NMPRC issued a final order
approving a CCN for 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 special retail contract, which includes power sales agreement for the facility, to replace the
existing load retention agreement which was approved by final order issued October 5, 2016 in NMPRC Case No. 16-00224-UT.
Construction of the solar generation facility is expected to be completed in the second quarter of 2017.
Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case
No. 15-00280-UT to issue up to $310.0 million of new long-term debt and to guarantee the issuance of up to $65.0 million of new
debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval
supersedes prior approvals. Under this authorization, on March 24, 2016, the Company issued $150.0 million aggregate principal
amount of 5.00% Senior Notes due December 1, 2044. The net proceeds from the issuance of these senior notes, after deducting
the underwriters' commission, were $158.1 million. These proceeds include accrued interest of $2.4 million and a $7.1 million
premium before expenses. These senior notes constitute an additional issuance of the Company's 5.00% Senior Notes due 2044,
of which $150.0 million was previously issued on December 1, 2014, for a total principal amount outstanding of $300.0 million.
Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions,
recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC.
14
Federal Regulatory Matters
Four Corners. On June 26, 2015, APS filed an application requesting authorization from FERC to purchase 100% of the
Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and
rights. On December 22, 2015, FERC issued an order approving the proposed transaction. 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.
Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an
order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under the RCF up to $400.0 million
outstanding at any time, to issue up to $310.0 million in long-term debt, and to guarantee the issuance of up to $65.0 million of
new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from November 15, 2015
through November 15, 2017. This approval supersedes prior approvals.
Under this authorization, on March 24, 2016, the Company issued $150.0 million aggregate principal amount of 5.00%
Senior Notes due December 1, 2044. Additionally under this authorization, on January 9, 2017, the Company exercised its option
to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50.0 million to $350.0
million. The Company still has the option to extend the facility by one additional year to January 2021 and to increase the RCF
by up to $50.0 million (up to a total of $400.0 million) upon the satisfaction of certain conditions, more fully set forth in the
agreement, including obtaining commitments from lenders or third party financial institutions. Additionally, the Company agreed
to reduce the letters of credit commitment to $50.0 million from a total commitment, under the RCF, of $350.0 million.
Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and
other approvals as required by the FERC.
United States Department of Energy. The DOE regulates the Company's exports of power to the Comisión Federal de
Electricidad in Mexico pursuant to a license and two presidential permits issued by the DOE.
The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's
uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See "Facilities – Palo Verde" for discussion
of spent fuel storage and disposal costs.
Sales for Resale
The Company provides firm capacity and associated energy to the Rio Grande Electric Cooperative ("RGEC") pursuant to
an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission
service to the RGEC pursuant to the Company's Open Access Transmission Tariff ("OATT"). The contract includes a formula-
based rate that is updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible
fuel and purchased power costs allocable to the RGEC.
Power Sales Contracts
The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2016.
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 the City of Las Cruces, the second largest city in its service
territory. The Company provides electric distribution service to the City of Las Cruces under an implied franchise by satisfying
all obligations under the franchise agreement that expired 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 2.8% of the
Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss under which Fort Bliss takes
retail electric service from the Company under the applicable Texas tariffs. The Company serves White Sands under the applicable
New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under which the Company provides retail electric
service and limited wheeling services to HAFB under the applicable New Mexico tariffs. As stated in the contract, HAFB will
purchase the full output of a Company-owned 5 MW solar facility upon its completed construction, with HAFB's other power
requirements provided under the applicable New Mexico tariffs.
Other Information
Investors should note that we announce material financial information in our filings with the SEC, press releases and public
conference calls. Based on guidance from the SEC, we may also use the Investor Relations section of our website
(www.epelectric.com) to communicate with investors about the Company. It is possible that the financial information we post
there could be deemed to be material information. The information contained on or accessible from our website is not incorporated
by reference into and does not constitute a part of this Annual Report on Form 10-K.
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
PUCT Final Order established our current retail base rates in Texas, effective January 12, 2016. In addition, the NMPRC Final
Order established rates in New Mexico that became effective in July 2016.
Our profitability depends on our ability to recover the costs, including a reasonable return on invested capital, of providing
electric service to our customers through base rates approved by our regulators. These rates are generally established based on an
analysis of the expenses we incur in a historical test year, and as a result, the rates ultimately approved by our regulators may or
may not match our expenses at any given time and recovery of expenses may lag behind the occurrence of those expenses. Rates
in New Mexico may be established using projected costs and investment for a future test year period in certain instances. While
rate regulation is based on the assumption that we will have a reasonable opportunity to recover our costs and earn a reasonable
rate of return on our invested capital, there can be no assurance that our future Texas rate cases or New Mexico rate cases will
result in base rates that will allow us to fully recover our costs including a reasonable return on invested capital. There can be no
assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including costs
associated with future plant retirements. It is also likely that third parties will intervene in any rate cases and challenge whether
our costs are reasonable and necessary. If all of our costs are not recovered, or timely recovered, through the retail base rates
ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely
affect our ability to meet our financial obligations.
On February 13, 2017, we filed a general base rate case with the PUCT, Docket No. 46831 (the “2017 Texas rate case”),
respectively, to establish new rates and to request recovery of new plant placed into service since April 2015 of approximately
$444 million and to recover other cost of service increases. We anticipate that third parties will intervene in the 2017 Texas rate
case and we expect them to challenge the reasonableness and necessity of certain of our costs. While we cannot predict the outcome
or the timing of the 2017 Texas rate case at this time, we invoked our statutory right to have new rates relate back for consumption
on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be
surcharged or refunded to customers after the PUCT's final order in the 2017 Texas rate case. The PUCT has the authority to
require us to surcharge or refund such differences over a period not to exceed 18 months. If the PUCT does not increase our rates
adequately, our future operations, cash flow and financial condition could be materially and adversely affected. For a full discussion
of these rate cases see Part II, Item 8, "Financial Statements and Supplementary Data, Note C of Notes to Financial Statements."
We May Not Be Able To Recover All Costs of New Generation and Transmission Assets
We received approval, both from the PUCT and the NMPRC, to construct Units 3 and 4, two 89 MW simple-cycle
aeroderivative combustion turbines at MPS. In 2016, we completed construction of these units, which began commercial operation
in May 2016 and September 2016, respectively. We are exposed to the risk of failing to recover all costs associated with the
construction of MPS Units 3 and 4 and other new units and transmission assets.
In 2014 and 2016, we issued $150.0 million in aggregate principal amount of 5.00% Senior Notes, due December 1, 2044
for a total principal amount outstanding of $300.0 million. The net proceeds from the 5.00% Senior Notes along with borrowings
under our RCF were used to fund the construction of MPS and other capital additions. The costs of financing and constructing
these assets are subject to review by the PUCT and NMPRC. To the extent that the PUCT or the NMPRC determines that the costs
of construction are not reasonable because of cost overruns, delays or other reasons, we may not be allowed to recover these costs
from customers in base rates.
In addition, if future units are not completed on time, we may be required to purchase power or operate less efficient generating
units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the
PUCT and the NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting
from delays in the completion of these new units or other new units.
17
Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital
Programs and Increase Our Funding Obligations for Pensions and Decommissioning
In recent years, the global credit and equity markets and the overall economy have been extremely volatile. These and future
events could have a number of effects on our operations and capital programs. For example, tight credit and capital markets could
make it difficult and more expensive to raise capital to fund our operations and capital programs. If we are unable to access the
credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in the stock
market performance may reduce the value of our financial assets and decommissioning trust investments. Similarly, inflationary
increases will increase our future decommission obligations. Such market results may also increase our funding obligations for
our pension plans, other post-retirement benefit plans and nuclear decommissioning trusts. Changes in the corporate interest rates
that we use as the discount rate to determine our pension and other post-retirement liabilities may have an impact on our funding
obligations for such plans and trusts. Further, continued economic volatility may result in reduced customer demand, both in the
retail and wholesale markets, and increases in customer delinquencies and write-offs. Uncertainty in the credit markets may
negatively impact the ability of our customers to finance purchases of our services and could adversely affect the collectability of
our receivables. Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. For example,
during 2013, sales to public authorities and small commercial and industrial customers were negatively impacted by the federal
government sequestration and shutdown. The credit markets and overall economy may also adversely impact the financial health
of our suppliers. If that were to occur, our access to and prices for inventory, supplies and capital equipment could be adversely
affected. Our power trading counterparties could also be adversely impacted by the market and economic conditions which could
result in reduced wholesale power sales or increased counterparty credit risk. Declines in revenues, earnings and cash flow from
these events, could impact our ability to fund construction expenditures and impact the level of dividend payments.
There are Inherent Risks in the Ownership of Nuclear Facilities
Our 15.8% ownership interest in Palo Verde, which is the largest nuclear electric generating facility in the United States,
subjects us to a number of risks. A significant percentage of our generating capacity, off-system sales margins, assets and operating
expenses is attributable to Palo Verde. Our interest in each of the three Palo Verde units totals approximately 633 MW of generating
capacity. Palo Verde represents approximately 30% of our available net generating capacity and provided approximately 49% of
our energy requirements for the twelve months ended December 31, 2016. Palo Verde comprises approximately 25% of our total
net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the
operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and
costs at Palo Verde. Palo Verde operated at a capacity factor of 93.2% and 94.3% in the twelve months ended December 31, 2016
and 2015, respectively.
We participate in Palo Verde with one or more parties who may not have the same goals, strategies, priorities or resources
as we do and may compete with us. Furthermore, regulatory compliance issues and financial restraints could cause these parties
to make decisions that could potentially be adverse to us.
As Palo Verde is a nuclear electric generating facility it is subject to environmental, health and financial risks, such as the
ability to obtain adequate supplies of nuclear fuel and water; the ability to dispose of spent nuclear fuel; increases in decommissioning
costs due to inflation and regulatory changes, the ability to maintain adequate trust fund reserves for decommissioning; potential
liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; cyber
attacks, or other causes; and unscheduled outages due to equipment and other problems. If a nuclear incident were to occur at Palo
Verde, it could materially and adversely affect our results of operations and financial condition. A major incident at a nuclear
facility anywhere in the world could cause regulatory bodies to limit or prohibit the operation or licensing of any domestic nuclear
unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.
We May Not Be Able to Recover All of Our Fuel Expenses from Customers On a Timely Basis Or at All
In general, by law, we are entitled to recover our reasonable and necessary fuel and purchased power expenses from our
customers in Texas and New Mexico. NMPRC Case No. 13-00380-UT provides for energy delivered to New Mexico customers
from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon a previous purchased
power contract. Fuel and purchased power expenses in Texas and New Mexico are subject to reconciliation by the PUCT and
NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs such that fuel revenues equal
recoverable fuel and purchased power expense including the re-priced energy costs for Palo Verde Unit 3 in New Mexico. In the
event that recovery of fuel and purchased power expenses is denied in any reconciliation proceeding, the amounts recorded for
fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would
incur a loss to the extent of the disallowance.
18
In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust
for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. In
Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision
except in the month of December. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any
time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods
of significant increases in natural gas prices, we realize a lag in the ability to reflect increases in fuel costs in our fuel recovery
mechanisms in Texas. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from
customers. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely
recovery of such costs, we could experience a material negative impact on our cash flow.
Weather Conditions Affect the Demand for Electricity or Could Result in Unplanned Outages
Our service territory is in west Texas and southern New Mexico and is particularly susceptible to dry and hot temperatures
in the summer months. These seasonal weather patterns result in temperatures that can lead to daytime highs exceeding 100 degrees
Fahrenheit for extended periods during the summer when we typically experience peak kWh sales at higher summer rates. Milder
temperatures during this period will occur occasionally and result in less kWh sales which will adversely affect our results of
operations. From time to time, we experience extreme weather conditions, including high winds (usually in the spring months
but can occur during other months), that may result in unplanned outages. Under such conditions, we may incur additional costs
to repair and, or, to replace equipment. Depending upon the length and extent of the damage, we may also incur additional purchase
power costs. Fallen power lines and poles can cause severe damage to customer property and subject us to claims, all of which
could have a material adverse effect on our results of operations and cash flows.
Equipment Failures and Other External Factors Can Adversely Affect Our Results
The generation and transmission of electricity require the use of expensive and complex equipment. While we have a
maintenance program in place, generating plants are subject to unplanned outages because of equipment failure and severe weather
conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these
units. In the event of unplanned outages, we must acquire power from other sources at unpredictable costs in order to supply our
customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and
approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and
purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to
the extent of the disallowance. This could materially increase our costs and prevent us from selling excess power at wholesale. In
addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus
subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We may also incur additional
capital and operating costs in connection with the physical security and cyber security of transmission lines and generation facilities.
Damage to certain transmission and generation facilities due to vandalism or other deliberate acts, or damage due to severe weather
could lead to outages or other adverse effects. We are particularly vulnerable to this because a significant portion of our available
energy (at Palo Verde) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over
long distance transmission lines. In addition, Palo Verde’s availability is an important factor in realizing off-system sales margins.
These factors, as well as interest rates, economic conditions, fuel prices and price volatility could have a material adverse effect
on our earnings, cash flow and financial position. While we believe we maintain adequate insurance coverage for such incidents,
there is no assurance that all costs in excess of deductible amounts will be reimbursed or that we can maintain such coverage limits
in the future at competitive market rates. In the event future insurance costs and/or deductible amounts increase, our financial
condition, operating results and cash flows could be materially adversely affected.
Competition and Deregulation Could Result in a Loss of Customers and Increased Costs
As a result of changes in federal law, our wholesale and large retail customers have access to, in varying degrees, alternative
sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate
our transmission and distribution functions, which would remain regulated, from our power generation and energy services
businesses, which would operate in a competitive market, in the future. In 2004, the PUCT approved a rule delaying retail
competition in our Texas service territory. This rule was codified in the PURA in June 2011. The PURA identifies various milestones
that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and
commencement of independent operation of a regional transmission organization in the area that includes our service territory.
This and other milestones are not likely to be achieved for a number of years, if at all. There is substantial uncertainty about both
the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas
service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable.
There can be no assurance that deregulation would not adversely affect our future operations, cash flow and financial condition.
19
Future Costs of Compliance with Environmental Laws and Regulations Could
Adversely Affect Our Operations and Financial Results
We are subject to extensive federal, state and local environmental laws and regulations relating to discharges into the air,
air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and
non-hazardous substances and wastes, natural resources, and health and safety. Compliance with these legal requirements, which
change frequently and often become more restrictive, could require us to commit significant capital and operating resources toward
permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchases of
air emission allowances and/or offsets. These laws and regulations could also result in limitations in operating hours and/or changes
in construction schedules for future generating units.
Cost of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not
recovered in our rates, could adversely affect our operations and financial results, especially if emission and/or discharge limits
are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and
types of assets we operate increase. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or
the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of
implementation of environmental laws or regulations. For example, the EPA has issued in the recent past various proposed
regulations regarding air emissions, such as the revision of the primary and secondary ground-level ozone NAAQS. If these
regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our
financial results.
Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for
Electricity or Availability of Resources, and Could Result in Increased Compliance Costs
We emit GHG (including carbon dioxide) through the operation of our power plants. Federal legislation had been introduced
in both houses of Congress to regulate GHG emissions and numerous states have adopted programs to stabilize or reduce GHG
emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA. Under EPA regulations finalized in May
2010, formerly known as the "Tailoring Rule", the EPA can impose GHG best achievable control technology requirements for
sources, including power plants already required to implement prevention of significant deterioration under the CAA for certain
other pollutants.
In addition, in October 2015, the EPA published a final rule establishing NSPS limiting CO2 emissions from new, modified
and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to
regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected
units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean
Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions
performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February
9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. Further, on September 3, 2016,
the U.S. signed the 21st Conference of Parties Paris Agreement, which requires countries to set and "represent a progression" in
GHG emission reduction goals every five years beginning in 2020. The potential impact of this agreement and GHG rules (if and
when finalized) on us is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or
changes in construction schedules for future generating units.
It is not possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi-state
regions or any GHG regulations adopted by the EPA or state environmental agencies will impact our business. However, any
legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional
operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit GHG, and could
have a material adverse effect on our business, financial condition, reputation or results of operations.
Adverse Regulatory Decisions or Changes in Applicable Regulations Could Have a Material Adverse Effect on Our
Business or Result in Significant Additional Costs
Our business is subject to extensive federal, state and local laws and regulations regarding safety and performance, siting
and construction of facilities, customer service and the rates we can charge our customers, among other things. FERC regulates
our wholesale operations, provision of transmission services and compliance with federally mandated reliability standards. FERC
has issued a number of rules pertaining to preventing undue discrimination in transmission services and electric reliability standards.
Under the Energy Policy Act of 2005, FERC can impose penalties (up to $1,213,503 per violation, per day) for failure to comply
with statutes, rules and orders within FERC's jurisdiction, including mandatory electric reliability standards. Additional regulatory
authorities have jurisdiction over some of our operations and construction projects, including the EPA, the DOE, the PUCT, the
NMPRC and various local regulatory districts (including the cities of El Paso and Las Cruces).
20
We must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective
orders. Should we be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any
investigations or enforcement actions or impose penalties or disallowances on us, our business could be adversely affected. Existing
regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to us or our
facilities in a manner that may have a detrimental effect on our business or result in significant additional costs because of our
obligation to comply with those requirements.
Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our Infrastructure Could
Interfere With Our Operations, Could Expose Us or Our Customers or Employees to a Risk of Loss, and Could Expose
Us to Liability, Regulatory Penalties, Reputational Damage and Other Harm to Our Business
We rely upon our infrastructure to manage or support a variety of business processes and activities, including the generation,
transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers.
We also use information technology systems for internal accounting purposes and to comply with financial reporting, legal and
tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns
due to attacks by hackers, breaches due to employee error or malfeasance, system failures, computer viruses, natural disasters, a
physical attack on our facilities, or other catastrophic events. The occurrence of any of these events could impact the reliability of
our generation, transmission and distribution systems and energy marketing and trading functions; could expose us or our customers
or employees to a risk of loss or misuse of confidential information; and could result in legal claims or proceedings, liability or
regulatory penalties against us, damage our reputation or otherwise harm our business. In addition, we may be required to incur
significant costs to prevent or respond to damage caused by these disruptions or security breaches in the future.
Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy
industry in general. The effects of such attacks against us or others in the energy industry could increase the cost of regulatory
compliance, increase the cost of insurance coverage or result in a decline in the U.S. economy which could negatively affect our
results of operations and financial condition. Ongoing and future governmental efforts to regulate cybersecurity in the energy
industry could lead to increased regulatory compliance costs.
The Effects of Technological Advancement, Energy Conservation Measures and Distributed Generation Could
Adversely Affect Our Operations and Financial Results
New technologies may emerge that could be superior to, or may not be compatible with, some of our existing technologies,
and may require us to make significant expenditures to remain competitive. Our future success will depend, in part, on our ability
to anticipate and adapt to technological changes in a cost-effective manner and to offer, on a timely basis, services that meet
customer demands and evolving industry standards.
Additionally, the electric utility industry is undergoing other technological advances such as the expanded cost effective
utilization of energy efficiency measures and distributed generation including solar rooftop projects. Customers’ increased use of
energy efficiency measures and distributed generation could result in lower demand. Reduced demand due to energy efficiency
measures and the use of distributed generation, to the extent not substantially offset through ratemaking mechanisms, could have
a material adverse impact on our financial condition, results of operations and cash flows.
Inflation Could Adversely Affect Our Financial Results
For the past several years, inflation has been relatively low and, therefore has had little impact on our results of operations
and financial condition. However, should we experience increases in costs due to inflationary impacts, any delays in requesting
and receiving compensatory increases in our base rates could have a material adverse impact on our financial condition, results
of operations and cash flows.
Our Line of Business Is Concentrated Solely to the Electric Industry and to One Region
We are a fully vertically integrated electric utility company whose only business is the generation, transmission and distribution
of electricity to customers in an area of approximately 10,000 square miles in west Texas and southern New Mexico. Approximately
91% of revenues are directly related to the retail sales of electric power to approximately 400,000 residential, commercial and
public authority customers. As such, risks uniquely associated with the utility industry such as changes in utility legislation and
regulations, weather patterns in the region and economic conditions will have a greater effect on our overall operating results than
otherwise if our operations were more diversified into other lines of business and in a broader geographical area.
21
New Laws, Regulations and Policies Announced by the Trump Administration Could Impact Our Operations
President Donald Trump campaigned on a number of issues, including increasing border security and immigration regulations,
overhauling federal taxes, repealing the Patient Protection Affordable Care Act, withdrawal from the Trans Pacific Partnership
agreement, enacting duties on NAFTA imports and reducing the burdens of environmental and climate control regulations. Since
President Trump’s inauguration, he has initiated executive orders towards achieving some of these goals; however it is uncertain
to what extent President Trump proposes additional new executive orders and the effect such orders will have on the national,
regional and local economies. Our service territory borders with Mexico and as such businesses in our service territory rely heavily
on commerce with businesses in Mexico. Changes in regulations restricting such commerce activities could reduce our customer
growth rate and materially adversely affect our results of operations, financial condition and cash flows.
Both the new administration and the Republicans in the House of Representatives have made public statements in support
of comprehensive tax reform, including significant changes to the United States corporate income tax laws. These proposed changes
include, among other things, a reduction in the corporate income tax rate, the immediate deductibility of 100% of capital
expenditures, and the elimination of the interest expense deduction. We are currently unable to predict whether these reform
discussions will result in any significant changes to existing tax laws, or if any such changes would have a cumulative positive or
negative impact on us. However, it is possible that changes in the United States federal income tax laws could have a material
adverse effect on our results of operations, financial condition, and cash flows.
The Operation of Transmission Lines on Public and Private Properties, including Indian Lands, Could Result in
Uncertainty Related to Continued Easements and Rights-of-way and Significantly Impact Our Business
Portions of our transmission lines are located on public and private properties, including Indian lands, pursuant to easements
or other rights-of-way that are effective for specified periods. We are unable to predict the final outcome of pending or future
approvals by applicable property owners and governing bodies with respect to renewals of these easements and rights-of-way.
Provisions in Our Corporate Documents, Franchise Agreements and State Law Could Delay or Prevent a Change in
Control of the Company, Even if That Change Would Be Beneficial to Our Shareholders
Our Articles of Incorporation and Bylaws contain provisions that may make acquiring control of the Company difficult and
could preclude our shareholders from receiving a change of control premium, including:
•
•
•
•
•
provisions relating to the classification, nomination and removal of our directors;
provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;
provisions limiting the ability to call special meetings of the shareholders to the Chairman of the Board, our Chief Executive
Officer, our Secretary, the majority of the Board of Directors or the holders of at least 25% of the outstanding shares of
our capital stock entitled to vote at such meeting;
provisions restricting our ability to engage in a wide range of “Business Combination” transactions with an “Interested
Shareholder” (generally, any person who owns 15% or more of our outstanding voting power) or any affiliate or associate
of an Interested Shareholder, unless specific conditions are met; and
the authorization given to our Board of Directors or any duly designated committee to issue and set the terms of preferred
stock.
Our El Paso franchise agreement states that any assignment of the franchise agreement, including a deemed assignment as
a result of a change in control of the Company, requires the consent of the City of El Paso. In addition, approval of the NMPRC,
PUCT and FERC would likely be required in any transaction involving a change of control.
In addition, Texas law prohibits us from engaging in a business combination with any shareholder for three years from the
date that person became an affiliated shareholder by beneficially owning 20% or more of our outstanding common stock, in the
absence of certain board of director or shareholder approvals.
22
Item 1B.
Unresolved Staff Comments
None.
Item 2.
Properties
The principal properties of the Company are described in Item 1, "Business," and such descriptions are incorporated herein
by reference. Transmission lines are located either on company-owned land, private rights-of-ways, easements or on streets or
highways by public consent.
The Company owns an executive and administrative office building and the Eastside Operations Center ( the "EOC"), which
opened in early 2015, in El Paso County, Texas. The Company leases land in El Paso, Texas, adjacent to Newman under a lease
which expires in June 2033, subject to a renewal option of 25 years. The Company has several other leases for office and parking
facilities that expire within the next four years.
Item 3.
Legal Proceedings
The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory
commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters,
the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly
analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual
disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the
matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect
on the financial position, results of operations or cash flows of the Company.
See Item 1, "Business – Environmental Matters and Regulation," and Part II, Item 8, "Financial Statements and Supplementary
Data, Note C, Note L and Note K of Notes to Financial Statements" for discussion of the effects of government legislation and
regulation on the Company as well as certain pending legal proceedings.
Item 4.
Mine Safety Disclosures
Not Applicable.
23
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:
2015
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2016
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Sales Price
High
Low
Close
Dividends
(End of period)
$
$
$
$
41.32
39.26
38.32
40.35
46.20
47.27
48.75
48.35
$
$
35.43
33.77
33.90
35.32
37.19
42.42
44.07
42.49
38.64
34.66
36.82
38.50
45.88
47.27
46.77
46.50
$
$
0.280
0.295
0.295
0.295
0.295
0.310
0.310
0.310
24
Performance Graph
The following graph compares the performance of the Company’s common stock to the performance of Edison Electric
Institute’s ("EEI") index of investor-owned electric utilities and the NYSE Composite, setting the value of each at December 31,
2011 to a base of 100. The table sets forth the relative yearly percentage change in the Company’s cumulative total shareholder
return, assuming reinvestment of dividends, as compared to EEI and the NYSE Composite, as reflected in the graph.
EE
EEI Index
NYSE Composite
12/31/2011
100
100
100
12/31/2012
96
102
113
12/31/2013
109
115
139
12/31/2014
128
149
145
12/31/2015
127
143
136
12/31/2016
158
168
148
As of January 31, 2017, there were 2,313 holders of record of the Company’s common stock. The Company has been
paying quarterly cash dividends on its common stock since June 30, 2011 and paid a total of $49.6 million in cash dividends
during the twelve months ended December 31, 2016. On January 26, 2017, the Board of Directors declared a quarterly cash
dividend of $0.31 per share payable on March 31, 2017 to shareholders of record at the close of business on March 17, 2017.
Typically, the Board of Directors reviews the Company’s dividend policy annually in the second quarter of each year.
Declaration and payment of dividends is subject to compliance with certain financial tests under Texas law. Since 1999, the
Company has also returned cash to shareholders through a stock repurchase program pursuant to which the Company has
bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s
program, purchases can be made at open market prices or in private transactions and repurchased shares are available for
issuance under employee benefit and stock incentive plans, or may be retired. On March 21, 2011, the Board of Directors
authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock (the "2011 Plan"). No shares
of common stock were repurchased during the twelve months ended December 31, 2016 under the 2011 Plan. The table below
provides the amount of the fourth quarter issuer purchases of equity securities.
Period
October 1 to October 31, 2016
November 1 to November 30, 2016
December 1 to December 31, 2016
Total
Number
of Shares
Purchased (a)
Average Price
Paid per Share
(Including
Commissions)
—
—
46.50
— $
—
5,579
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."
25
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:
Net income
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
$
$
$
$
2012
852,881
168,658
90,846
2.27
$
$
$
$
$
$
$
Weighted average number of shares outstanding
40,350,688
40,274,986
40,190,991
40,114,594
39,974,022
Diluted earnings per share:
Net income
Weighted average number of shares and dilutive
$
2.39
$
2.03
$
2.27
$
2.20
$
2.26
potential shares outstanding
40,408,033
40,308,562
40,211,717
40,126,647
40,055,581
Dividends declared per share of common stock
$
Cash additions to utility property, plant and equipment $
Total assets (a)
Long-term debt, net of current portion (a)
1.225
225,361
$
$
1.165
281,458
$
$
1.105
277,078
$
$
1.045
237,411
$
$
0.97
202,387
$ 3,376,278
$ 3,200,607
$ 3,033,400
$ 2,748,139
$ 2,637,183
$ 1,195,513
$ 1,122,660
$ 1,122,235
Common stock equity
$ 1,074,396
$ 1,016,538
$
984,254
$
$
988,436
943,833
$
$
987,960
824,999
________________
(a) The Company implemented Accounting Standards Update ("ASU") 2015-03, Interest- Imputation of Interest (Topic 715)
and ASU 2015-17, Balance Sheet Classification of Deferred Taxes in the first quarter of 2016, retrospectively to all periods
presented in the table above.
26
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
As you read this Management’s Discussion and Analysis of Financial Condition and Results of Operations, please refer to
our Financial Statements and the accompanying notes, which contain our operating results.
Summary of Critical Accounting Policies and Estimates
Our financial statements have been prepared in conformity with U.S. Generally Accepted Accounting Principles ("GAAP").
Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to Financial Statements contains a summary of
our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant
accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex,
subjective assumptions by management, which can materially impact reported results. The Company evaluates its estimates on
an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-
retirement obligations and asset retirement obligations ("ARO"). Changes in these estimates or assumptions, or actual results that
are different, could materially impact our financial condition and results of operation.
Regulatory Accounting
We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC
jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize
them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only
when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders,
regulatory precedent and the current regulatory environment. As of December 31, 2016, we had recorded regulatory assets currently
subject to recovery in future rates of approximately $118.9 million and regulatory liabilities of approximately $18.4 million as
discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Note D of the Notes to Financial
Statements. Regulatory tax assets of approximately $66.7 million, primarily related to the regulatory treatment of the equity portion
of allowance for funds used during construction ("AFUDC") and excess deferred income taxes, are included in regulatory assets.
In the event we determine that we can no longer apply the Financial Accounting Standards Board's (the "FASB") guidance
for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, based on regulatory
action, we could be required to record a charge against income in the amount of the unamortized balance of the related regulatory
assets. Such an action could materially reduce our total assets, specifically our total deferred charges and other assets, and
shareholders' equity.
Collection of Fuel Expense
In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times
of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT
on a periodic basis every one to three years. The NMPRC, in its discretion, may order that a prudence review be conducted to
assure that fuel and purchased power costs recovered from customers are prudently incurred. Prior to the completion of a
reconciliation proceeding or audit, we record fuel transactions such that fuel revenues, including fuel costs recovered through the
Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") in New Mexico, equal fuel expense. In the event that a
disallowance of fuel cost recovery occurs during a reconciliation proceeding or an audit, the amounts recorded for fuel and
purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss
to the extent of the disallowance.
On September 27, 2016, the Company filed an application with the PUCT, designated as PUCT Docket No. 46308, to
reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March
31, 2016. As of December 31, 2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation
are approximately $114.4 million. The NMPRC approved the continuation of its use of the FPPCAC without modification and
the Company’s application requesting reconciliation of fuel and purchased power costs through December 2012 in Case No.
13-00380-UT. The Company's request to reconcile its fuel and purchased power costs for the period January 1, 2013 through
December 31, 2014 was approved in Case No. 15-00127-UT. New Mexico jurisdictional costs subject to prudence review are
costs from January 1, 2015 through December 31, 2016 that total approximately $114.6 million.
The Company recovers fuel and purchased power costs from the RGEC pursuant to an ongoing contract with a two-year
notice to terminate provision. The contract includes a fuel adjustment clause designed to recover all eligible fuel and purchased
power costs allocable to the RGEC and is updated on an annual basis. This update is reviewed and approved by the RGEC annually
27
in February following the prior calendar year. As of December 31, 2016, the RGEC fuel costs subject to review were approximately
$1.4 million.
Decommissioning Costs and Estimated Asset Retirement Obligation
Pursuant to the ANPP Participation Agreement, the rules and regulations of the Nuclear Regulatory Commission and federal
law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The
determination of the estimated liability is based on site-specific estimates, which are updated every three years and involve numerous
judgments and assumptions, including estimates of future decommissioning costs at current price levels, escalation rates and
discount rates. The Palo Verde ARO is approximately $79.6 million and represents approximately 97% of our total ARO balance
of $81.8 million as of December 31, 2016. A 10% increase in the estimates of future Palo Verde decommissioning costs at current
price levels would have increased the ARO liability by approximately $7.8 million at December 31, 2016. For further details see
Part II, Item 8, "Financial Statements and Supplementary Data, Note E of Notes to Financial Statements."
We are required to fund estimated nuclear decommissioning costs over the life of the generating facilities through the use
of external trust funds pursuant to rules of the Nuclear Regulatory Commission, PUCT and the ANPP Participation Agreement.
Historically, in Texas and New Mexico, we have been permitted to collect the funding requirements for our nuclear decommissioning
trusts as part of our rates, except for a portion of Palo Verde Unit 3, which is deregulated in the New Mexico jurisdiction. While
we periodically attempt to seek to recover the costs of decommissioning obligations through our rates, we are not able to conclude,
given the currently available evidence, that it is probable these costs will continue to be collected over the period until
decommissioning begins in 2044. We are ultimately responsible for these costs, and our future actions combined with future
decisions from regulators will determine how successful we are in this effort.
The funding amounts are based on assumptions about future investment returns and future decommissioning cost escalations.
If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the nuclear plant increase
beyond our expectations, we would be required to increase our funding to the nuclear decommissioning trusts.
Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We
face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and
which were valued at $119.9 million as of December 31, 2016. A hypothetical 10% increase in interest rates would have reduced
the fair values of these funds by $1.4 million at December 31, 2016. Our decommissioning trust funds also include marketable
equity securities of approximately $129.8 million at December 31, 2016. A hypothetical 20% decrease in equity prices would have
reduced the fair values of these funds by $26.0 million at December 31, 2016. Declines in market prices could require that additional
amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements.
We do not anticipate expending monies held in the nuclear decommissioning trusts before 2044 or a later period when
decommissioning of Palo Verde begins.
Future Pension and Other Post-retirement Obligations
We maintain a qualified noncontributory defined benefit pension plan, which covers substantially all of our employees, and
two non-funded nonqualified supplement plans that provide benefits in excess of amounts permitted under the provisions of the
tax law for certain participants in the qualified plan. We also sponsor a plan that provides other post-retirement benefits, such as
health and life insurance benefits to retired employees. Our net obligations under these various benefit plans at December 31, 2016
totaled $129.9 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled
$3.8 million for the twelve months ended December 31, 2016.
During October 2016, we approved and communicated a plan amendment that resulted in a remeasurement of our other post-
retirement benefit plan. Effective January 1, 2017, retirees and dependents that are less than 65 years of age are offered a choice
between a $1,000 and $2,250 deductible plan. Additionally, retirees and dependents that are 65 years of age or greater are covered
by a fully insured Medicare advantage plan. The impact of these plan changes was a reduction in the other post-retirement benefit
plan obligation of $32.7 million as of December 31, 2016.
Our pension and other post-retirement benefit liabilities and the related net periodic benefit costs are calculated on the basis
of a number of actuarial assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life
expectancy of retirees and health care cost inflation. For 2016, the discount rates used to measure our year end liabilities are based
on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the
timing of the projected future benefit payments. As of December 31, 2016, the corresponding weighted-average discount rates
range from 3.76% to 4.36% depending upon the benefit plan.
28
Our overall expected long-term rate of return on assets for the pension trust fund is 7.0% effective January 1, 2017, which
is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. Our overall expected long-term rate
of return on assets for the other post-retirement benefits trust, on an after-tax basis, is 4.875% effective January 1, 2017. Both
expected long-term rates of return are based on the after-tax weighted average of the expected returns on investments. The expected
returns on investments in the pension trust and the other post-retirement benefits trust are based upon the target asset allocations
for the two trusts.
Our accrued post-retirement benefit liability and the service and interest components of the related net periodic benefit costs
are calculated using an actuarial assumption regarding health care cost inflation. For measurement purposes, a 6.5%, 7.5%, 4.5%
and 10.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017 for pre-65 medical,
pre-65 drug, post-65 medical and post-65 drug, respectively. The health care cost trend rates are assumed to decline steadily to an
ultimate rate of 4.5% by 2025 for pre-65 medical and by 2026 for pre-65 and post-65 drug. Post-65 medical trend is assumed to
be 4.5% for all years into the future. Assumed health care cost trend rates have a significant effect on the amounts reported for the
health care plan.
The estimated rate of compensation increase used in our Retirement Plans is 4.5% and is based on recent trends for all non-
union employees and the amounts we are contractually obligated for union employees.
In 2016, we changed the method used to estimate the service and interest components of net periodic benefit cost 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 in 2016, and is expected to result in a decrease in the service cost and interest cost components in future
periods. Historically, we estimated service and interest costs utilizing a single weighted-average discount rate derived from the
yield curve used to measure the benefit obligation at the beginning of the period. In 2016, we elected to utilize a full yield curve
approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the
benefit obligation to the relevant projected cash flows. We believe the new approach provides a more precise measurement of
service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding spot rates on the yield curve.
We accounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively. The change
in estimate decreased the service and interest components of net periodic benefit cost for pension and other post-retirement benefits
in 2016 by approximately $2.9 million and $0.8 million, respectively.
The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December
31, 2016 reported pension liability and our 2016 reported pension expense (in thousands):
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
$
(41,843)
51,463
$
N/A
N/A
6,615
(6,002)
(3,601)
4,343
(2,698)
2,698
1,241
(1,106)
29
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December
31, 2016 other post-retirement benefit obligations and our 2016 reported other post-retirement benefit expense (in thousands):
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
$
(9,631)
12,246
$
(1,329)
1,595
$
11,222
(8,951)
N/A
N/A
2,342
(1,919)
(376)
376
(276)
350
1,252
(973)
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.
When appropriate, we record a valuation allowance against deferred tax assets to reflect that these tax assets may not be
realized. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and
character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the
results of operations and financial position of the Company. There were no valuation allowances for deferred tax assets as of
December 31, 2016.
We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount
recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon settlement. The
unrecognized tax benefits that do not meet the recognition and measurement standards were $2.6 million as of December 31, 2016.
The following is an overview of our results of operations for the years ended December 31, 2016, 2015 and 2014. Net income
and basic earnings per share for the years ended December 31, 2016, 2015 and 2014 are shown below:
Overview
Net income (in thousands)
Basic earnings per share
Years Ended December 31,
2016
2015
2014
$
$
96,768
2.39
$
81,918
2.03
91,428
2.27
Financial Effect of the PUCT Final Order
On August 25, 2016, the PUCT approved the Unopposed Settlement and issued its final order in Docket No.44941 (the
"PUCT Final Order"), as proposed. See Part II, Item 8, "Financial Statements and Supplementary Data, Note C of Notes to Financial
Statements."
For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail
Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, in the third quarter of 2016, the Company
reported the cumulative effect of the PUCT Final Order, which related back to January 12, 2016.
30
The increase (decrease) on operations resulting from the PUCT Final Order is categorized in the following periods based on
consumption (in thousands):
Three Months Ended
Twelve
Months
Ended
March
31, 2016
June 30,
2016
September
30, 2016
December
31, 2016
December
31, 2016
Category
Retail non-fuel base rate increase:
Relate back
$
4,782
$
— $
— $
— $
4,782
Interim rates
Additional non-fuel base rate increase
for Four Corners
Base rate increase
457
708
—
10,417
15,138
—
26,012
867
—
1,328
—
853
6,321
3,756
6,321
Retail non-fuel base rate increase, total
$
5,947
$ 11,284
$
16,466
$
7,174
$
40,871
Miscellaneous service revenues
Revenue taxes
Depreciation
Rate case expense
AFUDC
Pre-tax increase
Income tax expense (a)
After-tax increase
353
(19)
2,491
—
(106)
8,666
4,104
400
(436)
2,510
—
(87)
$ 13,671
5,677
4,562
$
7,994
$
$
$
$
390
(643)
2,412
(600)
(72)
17,953
7,221
10,732
$
$
379
(238)
2,849
(395)
(52)
9,717
5,714
4,003
$
$
1,522
(1,336)
10,262
(995)
(317)
50,007
22,716
27,291
(a)
In the third quarter of 2016, the Company changed its accounting for state income taxes from the
flow-through method to the normalization method in accordance with the PUCT Final Order and the
NMPRC Final Order. The impact of the change was additional income tax expense of $5.1 million for
the twelve months ended December 31, 2016.
31
The following table and accompanying explanations show the primary factors affecting the after-tax change in income
between the calendar years ended 2016 and 2015, 2015 and 2014, and 2014 and 2013 (in thousands):
Prior year December 31 net income
Changes (net of tax):
Increased (decreased) retail non-fuel base revenues
Decreased (increased) depreciation and amortization
Increased (decreased) non-base revenue, net of energy expense
Changes in the effective tax rate
(Decreased) increased allowance for funds used during
construction
Increased interest on long-term debt (net of capitalized interest)
(Decreased) increased investment and interest income
Increased taxes other than income taxes
Other
Current year December 31 net income
$
2016
2015
2014
$
81,918
$
91,428
$
88,583
28,802 (a)
3,580 (d)
804
(5,343) (i)
(4,887) (k)
(3,700) (n)
(2,784) (p)
(1,168) (s)
(454)
96,768
$
9,290 (b)
(4,214) (e)
(5,370) (g)
1,540 (j)
(4,953) (l)
(4,516) (o)
3,084 (q)
(641)
(3,730)
81,918
$
(3,533) (c)
(2,415) (f)
3,779 (h)
15
6,157 (m)
(390)
5,309 (r)
(3,252) (t)
(2,825)
91,428
______________________
Footnotes reflect pre-tax amounts
(a)
(b)
Increased retail non-fuel base revenues primarily due to the recognition of $40.9 million related to the PUCT Final Order.
Retail non-fuel base revenues increased, primarily due to (i) increased revenues of $11.9 million from our residential
customers due to hotter weather in the third quarter of 2015 contributing to a 4.9% increase in kWh sales; (ii) increased
revenues of $2.0 million from small commercial and industrial customers due to a 1.1% increase in kWh sales resulting
from hotter weather and a 1.6% increase in the average number of customers and (iii) a $1.2 million increase from large
commercial and industrial customers. These increases were partially offset by an $0.8 million decrease from sales to
public authorities due to a military installation moving a portion of their load to an interruptible rate.
Retail non-fuel base revenues decreased, primarily due to (i) a $3.0 million reduction in revenues from sales to public
authorities reflecting increased use of an interruptible rate at a military installation in our service territory as well as other
energy saving programs at military installations; (ii) a $2.3 million decrease in sales to residential customers primarily
due to milder weather; and (iii) a $1.0 million decrease in sales to large commercial and industrial customers.
Depreciation and amortization decreased primarily due to (i) a reduction of approximately $10.9 million resulting from
changes in depreciation rates approved in the PUCT Final Order and the NMPRC Final Order and (ii) the sale of the
Company's interest in Four Corners. These decreases were partially offset by an increase in plant, primarily due to MPS
Units 1 and 2 and the EOC each being placed in service in March 2015, and MPS Units 3 and 4 being placed in service
in May 2016 and September 2016, respectively.
Depreciation and amortization increased due to increased depreciable plant balances including MPS Units 1 and 2 and
the EOC which began commercial operation in the first quarter of 2015, partially offset by a change in the estimated
useful life of certain large intangible software systems.
Depreciation and amortization increased due to increased depreciable plant balances including Rio Grande Unit 9, which
began commercial operation in the second quarter of 2013.
Non-base revenues, net of energy expenses decreased due to: (i) a decrease of $5.3 million in deregulated Palo Verde
Unit 3 revenues; (ii) the recognition in 2014 of Palo Verde performance rewards of $2.2 million associated with the 2009
to 2012 performance periods, net of disallowed fuel and purchased power costs related to the resolution for the Texas
fuel reconciliation proceeding designated as PUCT Docket No. 41852; and (iii) a decrease of $0.7 million in energy
efficiency bonuses awarded. These decreases were partially offset by an increase of $1.7 million in transmission wheeling
revenues.
Non-base revenues, net of energy expenses increased due to: (i) recognition of $2.2 million in Palo Verde performance
rewards associated with the 2009 to 2012 performance periods, net of disallowed fuel and purchased power costs related
to the resolution of the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852; (ii) a $2.0 million
Texas Energy Efficiency bonus awarded in the fourth quarter of 2014 and (iii) an increase of $3.6 million in deregulated
Palo Verde Unit 3 revenues. The increase was partially offset by a decrease of $3.3 million in transmission wheeling
revenues.
The effective tax rate increased due to the change to normalize state income taxes in accordance with the PUCT Final
Order and the NMPRC Final Order.
(c)
(d)
(e)
(f)
(g)
(h)
(i)
32
(j)
(k)
(l)
(m)
(n)
(o)
(p)
(q)
(r)
(s)
(t)
The effective tax rate decreased due to a decrease in state income taxes and an increase in decommissioning income.
These decreases were partially offset by a decrease in AEFUDC and the loss of the domestic production activities deduction
in 2015.
AFUDC decreased due to lower balances of CWIP, primarily due to the MPS units and the EOC being placed in service
in 2015 and 2016, and a reduction in the AFUDC rate effective January 2016 as a result of the PUCT Final Order.
AFUDC decreased primarily due to lower balances of construction work in process primarily due to MPS Units 1 and
2, and the EOC being placed in service during the first quarter of 2015 and a reduction in the AFUDC rate.
AFUDC increased, primarily due to higher balances of CWIP subject to AFUDC, reflecting construction work in progress
on MPS and the EOC.
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.
Investment and interest income decreased primarily due to lower realized gains on securities sold from the Company’s
Palo Verde decommissioning trust in 2016 compared to 2015. The net gains reported in 2016 and 2015 are primarily the
result of the Company's efforts to re-balance and further diversify its Palo Verde decommissioning trust fund investments.
Investment and interest income increased, primarily due to further diversification and re-balancing our Palo Verde
decommissioning trust fund equity portfolio.
Investment and interest income increased, primarily due to increased gains on the sales of equity investments in our Palo
Verde decommissioning trust funds.
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.
Taxes other than income taxes increased, primarily due to higher property tax values and assessment rates. Additionally,
in the first quarter of 2014, the Arizona tax district in which Palo Verde operates adjusted its 2013 property tax rate,
resulting in an additional charge of $1.3 million.
33
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 2016, 2015 and 2014.
Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment
mechanisms. Historically, a significant portion of fuel costs have been recovered through base rates in New Mexico. Effective
July 1, 2016, with the implementation of the NMPRC Final Order, fuel costs are no longer recovered through base rates. Beginning
July 1, 2016, all fuel costs are recovered through a fuel adjustment mechanism. We record deferred fuel revenues for the difference
between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. "Non-
fuel base revenues" refers to our revenues from the sale of electricity excluding such fuel costs.
Retail non-fuel base revenue percentages by customer class are presented below:
Residential
Commercial and industrial, small
Commercial and industrial, large
Sales to public authorities
Total retail non-fuel base revenues
Years Ended December 31,
2015
2014
2016
46%
32
6
16
100%
44%
33
7
16
100%
42%
34
7
17
100%
No retail customer accounted for more than 4% of our non-fuel base revenues during such periods. As shown in the table
above, residential and small commercial customers comprise 78% of our non-fuel base revenues. While this customer base is more
stable, it is also more sensitive to changes in weather conditions. The current rate structures in Texas and New Mexico reflect
higher base rates during the peak summer season of May through October and lower base rates from November through April for
our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and
revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base revenues
derived during each quarter for the periods presented:
January 1 to March 31
April 1 to June 30
July 1 to September 30
October 1 to December 31
Total
Years Ended December 31,
2016
2015
2014
17%
25
38
20
100%
18%
26
35
21
100%
19%
27
33
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 2016, 2015 and 2014.
Cooling degree days
Heating degree days
2016
2015
2014
2,811
1,851
2,839
2,095
2,671
1,900
10-year
Average
2,732
2,157
34
Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.5% and 1.4%
in 2016 and 2015, respectively. See the tables presented on pages 37 and 38 which provide detail on the average number of retail
customers and the related revenues and kWh sales.
Retail non-fuel base revenues. Retail non-fuel base revenues increased primarily due to the recognition of $40.9 million
related to the PUCT Final Order. Excluding the $40.9 million PUCT Final Order impact, for the twelve months ended December
31, 2016, retail non-fuel base revenues increased $3.4 million, pre-tax, or 0.6%, compared to the twelve months ended December
31, 2015. This increase was primarily due to increased revenues from residential customers of $3.5 million due to a 1.3% increase
in kWh sales and increased revenues from small commercial and industrial customers of $2.5 million due to a 0.8% increase in
kWh sales. Increased kWh sales from residential customers and small commercial and industrial customers were driven by a 1.4%
and 1.9% increase in the average number of customers, respectively, offset in part by milder weather during the twelve months
ended December 31, 2016 compared to the twelve months ended December 31, 2015. Revenues decreased $2.4 million from large
commercial and industrial customers during the twelve months ended December 31, 2016 compared to the twelve months ended
December 31, 2015 due to a 3.0% decrease in kWh sales, due primarily to reduced demand by the steel manufacturing industry,
and a decrease in surcharges billed to a large customer in 2016 compared to 2015. Revenues decreased $0.2 million from public
authority customers reflecting a 0.8% decrease in kWh sales. Cooling degree days were relatively consistent with 2015 and were
2.9% over the 10-year average. Heating degree days decreased 11.6% in 2016, compared to 2015, and were 14.2% below the 10-
year average.
Retail non-fuel base revenues increased $14.3 million, or 2.6%, for the twelve months ended December 31, 2015 when
compared to the twelve months ended December 31, 2014. This increase includes an $11.9 million increase in revenues from
residential customers and a $2.0 million increase in revenues from small commercial and industrial customers reflecting hotter
summer weather and increases of 1.3% and 1.6%, respectively, in the average number of residential customers and small commercial
and industrial customers. KWh sales to public authorities increased 1.5% while revenue declined by $0.8 million, primarily due
to a military installation moving a portion of their load to an interruptible rate. Retail non-fuel revenues from large commercial
and industrial customers increased $1.2 million due to a surcharge billed to a large customer. Cooling degree days increased 6.3%
in 2015, when compared to the same period in the prior year, and were 5.3% over the 10-year average. Heating degree days
increased 10.3% for 2015, compared to 2014, and were 3.6% below the 10-year average.
Fuel revenues. Fuel revenues consist of (i) revenues collected from customers under fuel recovery mechanisms approved
by the state commissions and the FERC, (ii) deferred fuel revenues which are comprised of the difference between fuel costs and
fuel revenues collected from customers and (iii) prior to July 1, 2016, fuel costs recovered in base rates in New Mexico.
In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor based upon an
approved formula at least four months after our last revision, except in the month of December. In addition, if we materially over-
recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge
to recover those costs. Fuel over and under recoveries are defined as material when they exceed 4% of the previous twelve months'
fuel costs. On April 15, 2015, we filed a request, which was assigned PUCT Docket No. 44633, to reduce our fixed fuel factor by
approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the materiality
threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and was approved by the PUCT
on May 20, 2015. On November 30, 2016, we filed a request, which was assigned PUCT Docket No. 46610, to increase our fixed
fuel factor by approximately 28.8% to reflect increased fuel expenses primarily related to an increase in the price of natural gas
used to generate power. The increase in the fixed fuel factor was effective on an interim basis January 3, 2017 and approved by
the PUCT on January 10, 2017. On September 27, 2016, we filed an application with the PUCT, designated as PUCT Docket No.
46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through
March 31, 2016.
In New Mexico, effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs
will no longer be recovered through base rates, as it was historically, but will be completely recovered through the Fuel and
Purchased Power Cost Adjustment Clause (the "FPPCAC"). Fuel and purchased power costs are reconciled to actual costs on a
monthly basis and recovered or refunded to customers the second succeeding month. The Company's request to reconcile its fuel
and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in the NMPRC Final Order.
In March 2015 and March 2016, $5.8 million and $1.6 million, respectively, were credited to customers through the applicable
fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage.
We under-recovered fuel costs by $14.9 million in the twelve months ended December 31, 2016. We over-recovered fuel
costs by $13.3 million and under-recovered $3.1 million in the twelve months ended December 31, 2015 and 2014, respectively.
At December 31, 2016, we had a net fuel under-recovery balance of $10.9 million, including an under-recovery of $11.1 million
in Texas offset by an over-recovery of $0.2 million in New Mexico.
35
Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily
made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations.
We have shared 100% of margins on non-arbitrage sales (as defined by the settlement in PUCT Docket No. 41852) and 50% of
margins on arbitrage sales with our Texas customers since April 1, 2014. For the period April 1, 2014 through June 30, 2015, our
total share of margins assignable to the Texas retail jurisdiction, on arbitrage and non-arbitrage off-system sales, could not exceed
10% of the total margins assignable to the Texas retail jurisdiction on all off-system sales. We are currently sharing 90% of off-
system sales margins with our New Mexico customers, and 25% of our off-system sales margins with our sales for resale customer
under the terms of their contract.
Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our
native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of
off-system energy generated from lower cost generating resources. Palo Verde's availability is an important factor in realizing
these off-system sales margins.
The table below shows MWhs, sales revenue, fuel cost, total margins and retained margins made on off-system sales for the
twelve months ended December 31, 2016, 2015 and 2014 (in thousands, except for MWhs).
MWh sales
Sales revenue
Fuel cost
Total margins
Retained margins
Years Ended December 31,
2016
1,927,508
45,702
38,933
6,769
1,137
$
$
$
$
2015
2,500,947
64,816
52,406
12,410
1,362
$
$
$
$
2014
2,609,769
97,980
74,716
23,264
2,147
$
$
$
$
Off-system sales revenue decreased $19.1 million, or 29.5%, and the related retained margins decreased $0.2 million, or
16.5%, for the twelve months ended December 31, 2016 when compared to 2015 as a result of lower average market prices for
power and a 22.9% decrease in MWh sales. Off-system sales revenues decreased $33.2 million, or 33.8%, and the related retained
margins decreased $0.8 million, or 36.6%, for the twelve months ended December 31, 2015 when compared to 2014 as a result
of lower average market prices for power and a 4.2% decrease in MWh sales.
36
Comparisons of kWh sales and operating revenues are shown below:
Years Ended December 31:
kWh sales (in thousands):
Retail:
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
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
Total fuel revenues (3)
Off-system sales:
Fuel cost
Shared margins
Retained margins
Total off-system sales
Other (4) (5)
Total operating revenues
Average number of retail customers (6):
Residential
Commercial and industrial, small
Commercial and industrial, large
Sales to public authorities
Total
2016
2015
Amount
Percent
Increase (Decrease)
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
$
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
$
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
32,591
886,936
$
30,690
849,869
$
$
362,138
41,014
49
5,303
408,504
356,969
40,250
49
5,250
402,518
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)
1,901
37,067
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)
6.2
4.4
1.4%
1.9
-
1.0
1.5
___________________________
(1)
(2)
Includes a $40.9 million increase resulting from the PUCT Final Order in 2016.
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.
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.
Includes an Energy Efficiency Bonus of $0.5 million and $1.3 million in 2016 and 2015, respectively.
Represents revenues with no related kWh sales and includes $1.5 million increase resulting from the PUCT Final Order in 2016.
The number of retail customers presented is based on the number of service locations.
(3)
(4)
(5)
(6)
37
Years Ended December 31:
kWh sales (in thousands):
Retail:
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
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential
Commercial and industrial, small
Commercial and industrial, large
Sales to public authorities
Total retail non-fuel base revenues
$
Wholesale:
Sales for resale
Total non-fuel base revenues
Fuel revenues:
Recovered from customers during the period
Under (over) collection of fuel (1)
New Mexico fuel in base rates
Total fuel revenues (2)
Off-system sales:
Fuel cost
Shared margins
Retained margins
Total off-system sales
Other (3) (4)
Total operating revenues
Average number of retail customers (5):
Residential
Commercial and industrial, small
Commercial and industrial, large
Sales to public authorities
Total
2015
2014
Amount
Percent
Increase (Decrease)
2,771,138
2,384,514
1,062,662
1,585,568
7,803,882
2,640,535
2,357,846
1,064,475
1,562,784
7,625,640
63,347
2,500,947
2,564,294
10,368,176
61,729
2,609,769
2,671,498
10,297,138
$
246,265
187,436
40,411
91,244
565,356
2,455
567,811
127,765
(13,342)
72,129
186,552
52,406
11,048
1,362
64,816
$
234,371
185,388
39,239
92,066
551,064
2,277
553,341
161,052
3,110
71,614
235,776
74,716
21,117
2,147
97,980
30,690
849,869
$
30,428
917,525
$
$
356,969
40,250
49
5,250
402,518
352,277
39,600
49
5,088
397,014
130,603
26,668
(1,813)
22,784
178,242
1,618
(108,822)
(107,204)
71,038
11,894
2,048
1,172
(822)
14,292
178
14,470
(33,287)
(16,452)
515
(49,224)
(22,310)
(10,069)
(785)
(33,164)
262
(67,656)
4,692
650
—
162
5,504
4.9%
1.1
(0.2)
1.5
2.3
2.6
(4.2)
(4.0)
0.7
5.1%
1.1
3.0
(0.9)
2.6
7.8
2.6
(20.7)
-
0.7
(20.9)
(29.9)
(47.7)
(36.6)
(33.8)
0.9
(7.4)
1.3%
1.6
-
3.2
1.4
_______________________
(1)
Includes the portion of DOE refund related to spent fuel storage of $5.8 million and $7.9 million in 2015 and 2014, respectively, that were credited to
customers through the applicable fuel adjustment clauses. 2014 includes $2.2 million related to Palo Verde performance rewards, net.
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.7 million and $15.0 million in 2015 and 2014, respectively.
Includes an Energy Efficiency Bonus of $1.3 million and $2.0 million in 2015 and 2014, respectively.
Represents revenues with no related kWh sales.
The number of retail customers presented is based on the number of service locations.
(2)
(3)
(4)
(5)
38
Energy expenses
Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased
power. After adding the new natural gas generating units (MPS Units 1 and 2) in March 2015 and (MPS Units 3 and 4) in May
2016 and September 2016, respectively, into the Company's system generating resources, Palo Verde represents approximately
30% of our available net generating capacity and approximately 58% of our Company-generated energy for the twelve months
ended December 31, 2016. Fluctuations in the price of natural gas, which is also the primary factor influencing the price of
purchased power, have had a significant impact on our cost of energy.
Energy expenses decreased $8.5 million, or 3.5%, for the twelve months ended December 31, 2016 compared to the twelve
months ended December 31, 2015, primarily due to (i) decreased natural gas costs of $10.6 million due to a 6.3% decrease in the
MWhs generated with natural gas and (ii) decreased coal costs of $7.8 million as a result of the sale of our interest in Four Corners,
a coal-fired generation station, on July 6, 2016. These decreases in energy expenses were partially offset by (i) increased total
purchased power of $6.2 million due to a 11.6% increase in the MWhs purchased and (ii) increased nuclear fuel expense of $3.7
million due to a $4.6 million reduction in the 2016 DOE refund compared to 2015.
Energy expenses decreased $73.9 million, or 23.4%, for the twelve months ended December 31, 2015 compared to 2014,
primarily due to (i) decreased natural gas costs of $62.5 million due to a 32.0% decrease in the average price of natural gas, (ii)
decreased total purchased power of $11.3 million due to a 18.7% decrease in the average price of total purchased power and (iii)
decreased nuclear fuel expense of $1.2 million due to a 7.2% decrease in the cost of nuclear fuel consumed. The decrease in energy
expense was partially offset by (i) a $2.1 million reduction in the 2015 DOE refund compared to 2014 and (ii) an increase in coal
costs of $1.0 million due to a 10.3% increase in the MWhs generated with coal.
The table below details the sources and costs of energy for 2016, 2015 and 2014.
2016
MWh
Cost per
MWh
2015
MWh
Cost per
MWh
Cost
(in thousands)
134,361
$
13,913
40,126 (b)
188,400
$
3,790,659
657,744
5,136,686
9,585,089
22,495
31,050
53,545
241,945
$
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
Cost
(in thousands)
123,806
$
6,154 (a)
43,778 (b)
173,738
$
3,550,904
175,258
5,093,844
8,820,006
Fuel Type
Natural Gas
Coal
Nuclear
Total
Purchase Power:
Photovoltaic
Other
Natural Gas
Coal
Nuclear
Total
Purchase Power:
Photovoltaic
Other
Total purchased power
Total energy
$
23,413
36,314
59,727
233,465
289,800
1,262,451
1,552,251
10,372,257
Fuel Type
Cost
2014
MWh
Cost per
MWh
(in thousands)
196,833
$
12,883
41,289 (b)
251,005
$
3,774,209
596,252
5,106,668
9,477,129
Total purchased power
Total energy
$
19,575
45,229
64,804
315,809
227,979
1,162,511
1,390,490
10,867,619
34.87
35.11
8.94
19.90
80.79
28.76
38.48
22.68
52.15
21.61
9.76
27.39
85.86
39.80
47.35
29.94
_____________________
(a) The sale of our interest in Four Corners, a coal-fired generation station, closed on July 6, 2016.
(b) Costs includes a DOE refund related to spent fuel storage of $1.8 million, $6.4 million, and $8.5 million recorded in 2016,
2015, and 2014, respectively. Cost per MWh excludes this settlement.
39
Other operations expense
Other operations expense decreased $0.9 million, or 0.4%, in 2016 compared to 2015, primarily due to (i) a $2.7 million
decrease in pension and benefits costs due to an amendment to the other post-retirement benefit plan and changes in actuarial
assumptions used to calculate expenses for the post-retirement benefit plans, partially offset by higher medical and other employee
benefit costs, (ii) decreased operations expense of $0.9 million at our fossil-fuel generating plants, primarily due to lower operating
costs as a result of the sale of our interest in Four Corners offset by increased operating expenses at the MPS, and (iii) decreased
other administrative and general expenses of $0.5 million. These decreases were partially offset by (i) a $2.3 million increase in
regulatory expenses, primarily related to the 2015 New Mexico and Texas rate cases being expensed, and (ii) increased transmission
and distribution expenses of $0.8 million.
Other operations expense increased $4.1 million, or 1.7%, in 2015 compared to 2014 primarily due to (i) a $4.0 million
increase in other operations payroll costs including a $1.5 million increase in employee incentive compensation; (ii) increased
pension and benefits costs due to changes in actuarial assumptions used to calculate expenses for the post-retirement benefit plan;
(iii) a $1.7 million increase in operations expenses at our fossil-fuel generating plants primarily due to expenses at our MPS with
no comparable expenses during 2014 and (iv) a $1.5 million increase in transmission and distribution expenses related to wheeling
expense and system support and improvements. These increases were partially offset by (i) a $1.9 million decrease in outside
services expenses and (ii) a $1.4 million decrease in operations expense at Palo Verde.
Maintenance expense
Maintenance expense increased $1.5 million, or 2.3%, in 2016 compared to 2015, primarily due to an increase in the level
of maintenance at Rio Grande and a planned outage at Four Corners, which was partially offset by a decrease in maintenance at
Newman. Maintenance expense decreased $0.4 million, or 0.6%, in 2015 compared to 2014, primarily due to a decrease in the
level of maintenance at our Rio Grande and Four Corners generating plants, which was partially offset by maintenance at our MPS
with no comparable expenses during 2014.
Depreciation and amortization expense
Depreciation and amortization expense decreased $5.5 million or 6.1%, in 2016 compared to 2015, primarily due to reductions
of approximately $10.9 million resulting from changes in depreciation rates approved in the PUCT Final Order and the NMPRC
Final Order, and the sale of the Company's interest in Four Corners in July 2016. These decreases were partially offset by an
increase in plant, primarily due to MPS Units 1 and 2 and the EOC being placed in service in March 2015, and MPS Units 3 and
4 being placed in service in May 2016 and September 2016, respectively.
Depreciation and amortization expense increased $6.5 million, or 7.8%, in 2015 compared to 2014, primarily due to the
increases in depreciable plant balances, including MPS Units 1 and 2 and the EOC, which were placed in service during the first
quarter of 2015, partially offset by an increase in the estimated useful lives of certain large intangible software systems effective
July 2015 in the amount of $1.8 million.
Taxes other than income taxes
Taxes other than income taxes increased $1.8 million, or 2.8%, in 2016 compared to 2015, primarily due to increased property
tax rates and valuations in Texas as a result of MPS Units 1 and 2 and the EOC being placed in service during the first quarter of
2015 and increased billed revenues in Texas. These increases were partially offset by decreased property taxes in Arizona due to
decreased property values. Taxes other than income taxes increased $1.0 million, or 1.6%, in 2015 compared to 2014, primarily
due to (i) higher property tax values and assessment rates and (ii) additional payroll taxes.
Other income (deductions)
Other income (deductions) decreased $7.2 million, or 27.8%, in 2016 compared to 2015, primarily due to (i) decreased
allowance for equity funds used during construction ("AEFUDC") resulting from lower average balances of construction work in
progress ("CWIP") and a reduction in the AEFUDC rate, and (ii) decreased investment and interest income due to lower realized
gains from our Palo Verde decommissioning trust fund equity portfolio.
Other income (deductions) decreased $2.3 million, or 8.1%, in 2015 compared to 2014, primarily due to (i) decreased
AEFUDC resulting from lower average balances of CWIP and a reduction in the AEFUDC rate and (ii) higher gains recognized
on the sales of land in 2014 compared to 2015. This decrease was partially offset by increased investment and interest income due
to further diversification and re-balancing of our Palo Verde decommissioning trust fund equity portfolio.
40
Interest charges (credits)
Interest charges (credits) increased by $7.6 million, or 13.8%, in 2016 compared to 2015, primarily due to interest expense
on the $150.0 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in March 2016 and decreased allowance
for borrowed funds used during construction ("ABFUDC") as a result of lower average balances of CWIP and a reduction in the
ABFUDC rate.
Interest charges (credits) increased by $8.4 million, or 18.0%, in 2015 compared to 2014 primarily due to interest expense
on the $150.0 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in December 2014 and decreased
ABFUDC as a result of lower balances of CWIP and a reduction in the ABFUDC rate.
Income tax expense
Income tax expense increased by $19.0 million, or 54.5%, in 2016 compared to 2015, primarily due to (i) an increase in the
pre-tax income and (ii) an increase in state income taxes due to normalization as discussed in Note J of the Notes to Financial
Statements and decreases in decommissioning trust income, which is taxed at a lower rate. Income tax expense decreased by
$6.2 million, or 15.1%, in 2015 compared to 2014, primarily due to (i) a decrease in the pre-tax income and (ii) a decrease in state
income taxes.
New accounting standards
In May 2014, the FASB 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. Early adoption of ASU 2014-09 is permitted after December 15, 2016, however,
we plan to adopt the new standard for reporting periods beginning after December 15, 2017.
Under the new standard, companies may use either of the following transition methods: (i) a full retrospective approach
reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii)
a modified retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption
(which includes additional footnote disclosures). We have not concluded which transition method we will elect but we currently
anticipate using the modified retrospective approach.
We are currently in the process of evaluating the impact of the new standard on our various revenue and cash flow streams,
including the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition and
disclosure under the new guidance. Tariff sales to customers are determined to be in the scope of the new standard and represent
a significant portion of our total operating revenues. We have not completed our final evaluation of tariff sales under the new
guidance but currently we do not anticipate that ASU 2014-09 will have a material impact on our revenue recognition for such
sales. We are still considering the impacts of the guidance on several industry-related accounting issues, including the accounting
for contributions in aid of construction ("CIAC"), assessing the collectability criterion and the presentation of revenues associated
with alternative revenue programs. Our initial assessment may change as we execute our implementation plan and new guidance
is provided by the American Institute of Certified Public Accountants Power and Utilities Industry Task Force.
In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and
Measurement of Financial Assets and Liabilities to enhance the reporting model for financial instruments by addressing certain
aspects of recognition, measurement, presentation, and disclosure. ASU 2016-01 generally requires entities to measure equity
investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any
changes in fair value in net income. The guidance for classifying and measuring investments in debt securities and loans is not
changed by this ASU, but requires entities to record changes in other comprehensive income. Financial assets and financial liabilities
must be separately presented by measurement category on the balance sheet or in the accompanying notes to the financial statements.
ASU 2016-01 clarifies the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in
combination with the entity's other deferred tax assets. The provisions of this ASU become effective for public companies for
fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Upon adoption of the new
standard, we expect to record the cumulative effects as of January 1, 2018 which will result in an adjustment to accumulated other
comprehensive income (losses) and retained earnings for unrealized gains (losses) related to equity securities owned by us. Had
we been required to adopt the new standard at January 1, 2016, accumulated other comprehensive income would decrease by
$28.8 million and retained earnings would increase by a corresponding amount. Furthermore, we would report for the year ended
41
December 31, 2016 an increase in investment income of $1.2 million, an increase in income tax expense of $0.2 million and a
decrease in other comprehensive income of $1.0 million. We continue to assess the future impact of this ASU.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among
organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring qualitative and quantitative
disclosures on leasing agreements. ASU 2016-02 maintains a distinction between finance leases and operating leases similar to
the distinction under previous leases guidance for capital leases and operating leases. The impact of leases reported in our operating
results and statement of cash flows are expected to be similar to previous GAAP. ASU 2016-02 requires the recognition in the
statement of financial position, by the lessee, of a liability to make lease payments (the lease liability) and a right-of-use asset
representing its right to use the underlying asset for the lease term. How leases are recorded in regard to financial position represents
a significant change from previous GAAP guidance. The lessee is permitted to make an accounting policy election to not recognize
lease assets and lease liabilities for short-term leases. Implementation of the standard for public companies will be required for
annual reporting periods beginning after December 15, 2018 and interim periods within that reporting period. Early adoption of
ASU 2016-02 is permitted for all entities, however, we plan to adopt the new standard for reporting periods beginning after
December 15, 2018. Adoption of the new lease accounting standard will require us to apply the new standard to the earliest period
using a modified retrospective approach. We are currently in the process of evaluating the impact of the new standard, including
the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure
under the new guidance, however, at this time we are unable to determine the impact this standard will have on the financial
statements and related disclosures.
In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718) Improvements to Employee
Share-Based Payment Accounting to simplify the accounting for share-based payment transactions, including the income tax
consequences, classification of awards either as equity or liabilities, and classification on the statements of cash flows. We will
adopt the new standard effective January 1, 2017 and do not expect the effect of the adoption to be material to our financial
condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard will be to increase net
operating loss carryforward deferred tax assets and retained earnings by approximately $0.2 million on January 1, 2017. We also
expect to continue to account for our outstanding stock awards based on the equity method and therefore do not anticipate any
changes in reporting related compensation expense.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326) ("ASU 2016-13"). ASU
2016-13 changes how companies measure and recognize credit impairment for many financial assets. The new current expected
credit loss model will require companies to immediately recognize an estimate of credit losses expected to occur over the remaining
life of the financial assets that are in the scope of the standard. The ASU also makes targeted amendments to the current impairment
model for available-for-sale debt securities. For public business entities, the provisions of ASU 2016-13 are effective for fiscal
years and interim periods within that reporting period beginning after December 15, 2019. Early implementation is permitted as
of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-13 will be
applied in a modified-retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of
the first reporting period in which the guidance is implemented. We are currently assessing the future impact of ASU 2016-13.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts
and Cash Payments to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement
of cash flows. The new guidance addresses the following classification issues: debt prepayment or debt extinguishment costs;
settlement of zero-coupon bonds; contingent consideration payments made after a business combination; proceeds from the
settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies, including bank-owned
life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and
separately identifiable cash flows and application of the predominance principle. For public business entities, the provisions of
ASU 2016-15 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2017.
Early adoption is permitted, including adoption in an interim period. If an entity elects early adoption of ASU 2016-15 in an interim
period, adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects
early adoption must adopt all of the amendments in the same period. ASU 2016-15 will be applied using a retrospective transition
method to each period presented. If it is impracticable to apply ASU 2016-15 retrospectively for some of the issues, the amendments
for those issues may be applied prospectively as of the earliest date practicable. We are currently assessing the future impact of
this ASU.
In December 2016, the FASB issued ASU 2016-19, Technical Corrections and Improvements, which amends a number of
Topics in the FASB ASC. This ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive
technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or
create a significant administrative cost to most entities. Most of the amendments are effective upon issuance of ASU 2016-19
while certain amendments that require transition guidance are effective for us beginning January 1, 2017. We believe we are in
42
compliance with those amendments that are effective immediately and that are applicable to us. We have not completed our
evaluation of the new standard for amendments that require transition guidance.
Inflation
For the last several years, inflation has been relatively low and, therefore, has had little impact on our results of operations
and financial condition.
Liquidity and Capital Resources
In March 2016, we issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044 to repay
outstanding short-term borrowings under our RCF used for working capital and general corporate purposes, which may include
funding capital expenditures. Despite such issuances of senior notes, we continue to maintain a strong balance of common stock
equity in our capital structure, which supports our bond ratings, allowing us to obtain financing from the capital markets at a
reasonable cost. At December 31, 2016, our capital structure, including common stock, long-term debt, current maturities of long-
term debt, and short-term borrowings under the RCF, consisted of 44.1% common stock equity and 55.9% debt. As of December
31, 2016, we had a balance of $8.4 million of cash and cash equivalents. Based on current projections, we believe that we will
have adequate liquidity through our current cash balances, cash from operations and available borrowings under our RCF to meet
all of our anticipated cash requirements for the next twelve months, including the upcoming maturities of long term debt.
Our principal liquidity requirements in the near-term are expected to consist of capital expenditures to expand and support
electric service obligations, expenditures for nuclear fuel inventory, interest payments on our indebtedness, cash dividend payments,
operating expenses including fuel costs, maintenance costs and taxes, payment of our $50.0 million Series B 4.47% Senior Notes
which mature in August 2017 and payment or remarketing of $33.3 million 2012 Series A 1.875% Pollution Control Bonds which
are subject to mandatory tender for purchase in September 2017.
Capital Requirements. During the twelve months ended December 31, 2016, our capital requirements primarily consisted
of expenditures for the construction and purchase of electric utility plant, cash dividend payments, and purchases of nuclear fuel.
Projected utility construction expenditures are to add new generation, expand and update our transmission and distribution systems,
and make capital improvements and replacements at Palo Verde and other generating facilities. On May 3, 2016 and September
15, 2016, we placed into commercial operation MPS Units 3 and 4, respectively, and the related common facilities and transmission
systems at a combined cost of approximately $160.5 million, including AFUDC, for the two units. Estimated cash construction
expenditures for all capital projects for 2017 are expected to be approximately $215 million. See Part I, Item 1, "Business –
Construction Program." Cash capital expenditures for new electric plant were $225.4 million in the twelve months ended December
31, 2016 compared to $281.5 million in the twelve months ended December 31, 2015. Capital requirements for purchases of
nuclear fuel were $42.4 million for the twelve months ended December 31, 2016, as compared to $42.0 million for the twelve
months ended December 31, 2015.
On December 30, 2016, we paid a quarterly cash dividend of $0.31 per share, or $12.6 million, to shareholders of record as
of the close of business on December 14, 2016. We paid a total of $49.6 million in cash dividends during the twelve months ended
December 31, 2016. On January 26, 2017, our Board of Directors declared a quarterly cash dividend of $0.31 per share payable
on March 31, 2017 to shareholders of record at the close of business on March 17, 2017 which will require cash of $12.5 million.
Typically, the Board of Directors reviews the Company's dividend policy annually in the second quarter of each year. In addition,
while we do not currently anticipate repurchasing shares of our common stock in 2017, we may repurchase shares of our common
stock in the future. Under our repurchase program, purchases can be made at open market prices or in private transactions, and
repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of
common stock were repurchased during the twelve months ended December 31, 2016. As of December 31, 2016, a total of
393,816 shares remain eligible for repurchase under the repurchase program.
We expect to continue to maintain a prudent level of liquidity and monitor market conditions for debt and equity securities.
We primarily utilize the distribution of dividends to maintain a balanced capital structure and supplement this effort with share
repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing
to make investments in new electric plant and other assets in order to reliably serve our customers.
Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced
by the timing of revenues and expenses recognized for income tax purposes. Due to net operating loss carryfowards resulting from
accelerated depreciation deductions, income tax payments are expected to be minimal in 2017.
We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans, and
decommissioning trust funds. We contributed $9.2 million and $10.9 million to our retirement plans during both the twelve months
43
ended December 31, 2016 and 2015, respectively. We contributed $1.7 million and $0.5 million to our other post-retirement benefit
plans during the twelve months ended December 31, 2016 and 2015, respectively. We contributed $4.5 million to our
decommissioning trust funds in both 2016 and 2015. We are in compliance with the funding requirements of the federal government
for our benefit plans. In addition, with respect to our nuclear plant decommissioning trust, we are in compliance with the funding
requirements of the federal law and the ANPP Participation Agreement. We will continue to review our funding for these plans in
order to meet our future obligations.
In 2010, we and RGRT, a Texas grantor trust through which we finance our portion of fuel for Palo Verde, entered into a
note purchase agreement with various institutional purchasers. Under the terms of the agreement, RGRT sold to the purchasers
$110.0 million aggregate principal amount of senior notes. In August 2015, $15.0 million of these senior notes matured and were
paid with borrowings under the RCF. In August 2016, $50.0 million of these senior notes were reclassified to current maturities
of long-term debt on our Balance Sheet, as they will mature in August 2017.
Capital Resources. Cash provided by operations, $231.2 million for the twelve months ended December 31, 2016 and $246.7
million for the twelve months ended December 31, 2015, is a significant source for funding capital requirements. The primary
factors affecting the change in cash flows from operations were increases in net under-collection of fuel revenues and accounts
receivable. Offsetting the decreases in cash flows from operations were increased revenues due to the PUCT Final Order and the
NMPRC Final Order and increases in deferred income taxes. Cash from operations has been impacted by the timing of the recovery
of fuel costs through fuel recovery mechanisms in Texas and New Mexico, and our sales for resale customer. We recover actual
fuel costs from customers through fuel adjustment mechanisms in Texas and New Mexico, and from our sales for resale customer.
We record deferred fuel revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded
to customers. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor at least
four months after our last revision except in the month of December based upon our approved formula which allows us to adjust
fuel rates to reflect changes in costs of natural gas. We are required to request to refund fuel costs in any month when the over-
recovery balance exceeds a threshold material amount and we expect fuel costs to continue to be materially over-recovered. We
are permitted to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount that we
expect fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material
when they exceed 4% of the previous twelve months' fuel costs. On November 30, 2016, we filed a request to increase our Texas
fixed fuel factor by approximately 28.8% to reflect increasing natural gas costs. This increase was effective with January 2017
billings. During the twelve months ended December 31, 2016, we had under-recoveries of fuel costs of $14.9 million compared
to over-recoveries of fuel costs of $13.3 million during the twelve months ended December 31, 2015. At December 31, 2016, we
had a net fuel under-recovery balance of $10.9 million, including an under-recovery of $11.1 million in the Texas jurisdiction
offset by an over-recovery of $0.2 million the New Mexico jurisdiction.
We maintain the RCF for working capital and general corporate purposes and financing nuclear fuel through RGRT. RGRT,
the trust through which we finance our portion of nuclear fuel for Palo Verde, is consolidated in our financial statements. On
January 9, 2017, we exercised our option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the
size of the facility by $50.0 million to $350.0 million. We still have the option to extend the facility by one additional year to
January 2021 and to increase the RCF by up to $50.0 million (up to a total of $400.0 million) upon the satisfaction of certain
conditions including obtaining commitments from lenders or third party financial institutions. Additionally, we agreed to reduce
the letters of credit commitment under the RCF to $50.0 million from a total commitment of $350.0 million. The total amount
borrowed for nuclear fuel by RGRT, excluding debt issuance costs, was $132.6 million at December 31, 2016, of which $37.6
million had been borrowed under the RCF, and $95.0 million was borrowed through senior notes. At December 31, 2015, the total
amounts borrowed for nuclear fuel by RGRT, excluding debt issuance costs, were $128.7 million of which $33.7 million had been
borrowed under the RCF and $95.0 million was borrowed through senior notes. Interest costs on borrowings to finance nuclear
fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered from customers through fuel recovery charges.
The outstanding balance for working capital and general corporate purposes was $44.0 million at December 31, 2016 and $108.0
million at December 31, 2015. Total aggregate borrowings under the RCF as of December 31, 2016 were $81.6 million, with
available borrowing capacity of $267.9 million thereunder, after giving consideration to the $50.0 million increase on January 9,
2017.
We received approval from the NMPRC on October 7, 2015 and from the FERC on October 19, 2015 to issue up to $310.0
million in new long-term debt and to guarantee the issuance of up to $65.0 million of new debt by RGRT to finance future purchases
of nuclear fuel and to refinance existing nuclear fuel debt obligations. We also requested approval from the FERC to continue to
utilize our existing RCF without change from the FERC’s previously approved authorization. The FERC authorization is effective
from November 15, 2015 through November 15, 2017. The approvals granted in these cases supersede prior approvals. Under
this authorization, on March 24, 2016, we issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December
1, 2044. The proceeds from the issuance of these senior notes, after deducting the underwriters' commission, were $158.1 million.
These proceeds included accrued interest of $2.4 million and a $7.1 million premium before expenses. The effective interest rate
for these senior notes is approximately 4.77%. The net proceeds from the sale of these senior notes were used to repay outstanding
44
short-term borrowings under the RCF. These senior notes constitute an additional issuance of our 5.00% Senior Notes due 2044,
of which $150.0 million aggregate principal amount was previously issued on December 1, 2014, for a total principal amount
currently outstanding of $300.0 million.
45
Contractual Obligations. Our contractual obligations as of December 31, 2016 are as follows (in thousands):
Revolving credit facility (4)
83,075
83,075
Payments due by period
Total
2017
2018 and
2019
2020 and
2021
2022 and
Beyond
$ 2,135,575
$
55,200
$
110,400
$
110,400
$ 1,859,575
434,253
106,307
43,675
54,503
19,918
4,536
19,918
47,268
350,742
—
—
—
—
—
61,261
15,454
165,915
25,427
—
—
—
—
—
—
58,538
22,558
—
—
12,726
12,726
335,992
84,960
11,498
4,500
9,940
50,278
21,521
11,498
4,500
808
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)
$ 3,218,826
$
337,784
$
217,278
$
255,527
$ 2,408,237
1,328
1,226
6,578
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 four series of pollution control bonds that are scheduled for remarketing and/or mandatory tender, one in 2017,
two in 2040, and one in 2042.
In 2010, the Company and RGRT entered into a note purchase agreement for $110.0 million aggregate principal amount
of senior notes consisting of: (a) $15.0 million aggregate principal amount of 3.67% RGRT Senior Notes, Series A, which
matured and were repaid on August 15, 2015; (b) $50.0 million aggregate principal amount of 4.47% RGRT Senior Notes,
Series B, due August 15, 2017; and (c) $45.0 million aggregate principal amount of 5.04% RGRT Senior Notes, Series C,
due August 15, 2020.
This reflects obligations outstanding under the $300.0 million RCF. At December 31, 2016, $44.0 million was borrowed
for working capital and general corporate purposes and $37.6 million was borrowed by RGRT for nuclear fuel. This
balance includes interest based on actual interest rates at the end of 2016 and assumes this amount will be outstanding
for the entire year of 2017.
Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2016. Gas
obligation includes a gas storage contract and a gas transportation contract.
Some of the nuclear fuel contracts are based on a fixed price, adjusted for a market index. The index used here is the
index at the end of 2016.
This obligation is based on our expected contributions and includes our minimum contractual funding requirements for
the non-qualified retirement income plan and the other post-retirement benefits for 2017. We have no minimum cash
contractual funding requirement related to our retirement income plan or other post-retirement benefits for 2017. However,
we are subject to minimum funding requirements of ERISA. We also may decide to fund at higher levels and expect to
contribute $11.5 million to our retirement plans in 2017, as disclosed in Part II, Item 8, Financial Statements and
Supplementary Data, Note M. Minimum funding requirements for 2018 and beyond are not included due to the uncertainty
of the applicable interest rates and the related return on assets.
This obligation is based on our anticipated contributions in 2017. We have no minimum funding obligation in either the
Texas or New Mexico jurisdiction effective February 1, 2016 with PUCT Docket No. 44941 and July 1, 2016 with
NMPRC Case No. 15-00127-UT, respectively. However, we continued to fund at the same funding levels of $0.4 million
(2)
(3)
(4)
(5)
(6)
(7)
(8)
46
(9)
per month in 2016. We expect our funding requirements to change in the future based on amounts requested in our
upcoming rate filings in both jurisdictions.
We lease land in El Paso, Texas, adjacent to Newman under a lease that expires in June 2033, subject to a renewal option
of 25 years. We also have several other leases for office, parking facilities and equipment that expire within the next four
years.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our
financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or
capital resources.
47
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
The following discussion regarding our market-risk sensitive instruments contains forward-looking information involving
risks and uncertainties. The statements regarding potential gains and losses are only estimates of what could occur in the future.
Actual future results may differ materially from those estimates presented due to the characteristics of the risks and uncertainties
involved.
We are exposed to market risk due to changes in interest rates, equity prices and commodity prices. Substantially all financial
instruments and positions we hold are for purposes other than trading and are described below.
Interest Rate Risk
Our long-term debt obligations are all fixed-rate obligations, except for the RCF, which is based on floating rates.
To the extent the RCF is utilized for nuclear fuel purchases, interest rate risk, if any, related to the RCF is substantially
mitigated through the operation of the PUCT and the NMPRC rules, which establish energy cost recovery clauses. Under these
rules, actual energy costs, including interest expense on nuclear fuel financing, are recovered from our customers.
Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We
face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and
which were valued at $119.9 million and $113.3 million as of December 31, 2016 and 2015, respectively. A hypothetical 10%
increase in interest rates would reduce the fair values of these funds by $1.4 million and $1.2 million at December 31, 2016 and
2015, respectively.
Equity Price Risk
Our decommissioning trust funds include marketable equity securities of approximately $129.8 million and $117.5 million
at December 31, 2016 and 2015, respectively. A hypothetical 20% decrease in equity prices would have reduced the fair values
of these funds by $26.0 million and $23.5 million based on their fair values at December 31, 2016 and 2015, respectively. Declines
in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum
funding requirements. We do not expect to expend monies held in trust before 2044 or a later period when decommissioning of
Palo Verde begins.
Commodity Price Risk
We utilize contracts of various durations for the purchase of natural gas and uranium concentrates to effectively manage our
available fuel portfolio. These agreements contain variable pricing provisions and are settled by physical delivery. The fuel contracts
with variable pricing provisions, as well as substantially all of our purchased power requirements, are exposed to fluctuations in
prices due to unpredictable factors, including weather and various other worldwide events, which impact supply and demand.
However, our exposure to fuel and purchased power price risk is substantially mitigated through the operation of the PUCT and
NMPRC rules and our fuel clauses, as discussed previously.
In the normal course of business, we enter into contracts of various durations for the forward sales and purchases of electricity
to effectively manage our available generating capacity and supply needs. Such contracts include forward contracts for the sale
of generating capacity and energy during periods when our available power resources are expected to exceed the requirements of
our retail native load and sales for resale. We also enter into forward contracts for the purchase of wholesale capacity and energy
during periods when the market price of electricity is below our expected incremental power production costs or to supplement
our generating capacity when demand is anticipated to exceed such capacity. As of January 31, 2017, we had entered into forward
sales and purchase contracts for energy as discussed in Part I, Item 1, "Business – Energy Sources – Purchased Power." These
agreements are generally fixed-priced contracts that qualify for the "normal purchases and normal sales" exception provided in
the FASB guidance for accounting for derivative instruments and hedging activities and are not recorded at their fair value in our
financial statements. Because of the operation of the PUCT and the NMPRC rules and our fuel clauses, these contracts do not
expose us to significant commodity price risk.
48
Management Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial
reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities
Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal
financial officers and affected by the Company’s board of directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles and includes those policies and procedures that:
•
•
•
pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions
of the assets of the Company;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and the receipts and expenditures of the Company are being
made only in accordance with authorizations of management and directors of the Company; and
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of
the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of
December 31, 2016. In making this assessment, the Company’s management used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission's 2013 Internal Control - Integrated Framework. Based on its assessment,
management believes that, as of December 31, 2016, the Company’s internal control over financial reporting is effective based
on those criteria.
The Company’s independent registered public accounting firm, KPMG LLP, has issued an audit report on the Company’s
internal control over financial reporting. This report appears on page 51 of this report.
49
Item 8.
Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Balance Sheets as of December 31, 2016 and 2015
Statements of Operations for the years ended December 31, 2016, 2015, 2014
Statements of Comprehensive Operations for the years ended December 31, 2016, 2015, and 2014
Statements of Changes in Common Stock Equity for the years ended December 31, 2016, 2015, 2014
Statements of Cash Flows for the years ended December 31, 2016, 2015, 2014
Notes to Financial Statements
Page
51
52
54
55
56
57
58
50
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
El Paso Electric Company:
We have audited the accompanying balance sheets of El Paso Electric Company (the Company) as of December 31, 2016 and
2015, and the related statements of operations, comprehensive operations, changes in common stock equity, and cash flows for
each of the years in the three-year period ended December 31, 2016. We also have audited El Paso Electric Company’s internal
control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). El Paso Electric Company’s
management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and
for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management
Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and
an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements
are free of material misstatement and whether effective internal control over financial reporting was maintained in all material
respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating
the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing
such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of El Paso
Electric Company as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the years in
the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. Also in our
opinion, El Paso Electric Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO).
/s/ KPMG LLP
Houston, Texas
February 24, 2017
51
EL PASO ELECTRIC COMPANY
BALANCE SHEETS
ASSETS
(In thousands)
Utility plant:
Electric plant in service
Less accumulated depreciation and amortization
Net plant in service
Construction work in progress
Nuclear fuel; includes fuel in process of $57,315 and $51,854, respectively
Less accumulated amortization
Net nuclear fuel
Net utility plant
Current assets:
Cash and cash equivalents
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,156
and $2,046, 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
Total assets
See accompanying notes to financial statements.
December 31,
2016
2015
$ 3,791,566
(1,244,332)
2,547,234
154,738
$ 3,616,301
(1,329,843)
2,286,458
293,796
194,842
(75,602)
119,240
190,282
(75,031)
115,251
2,821,212
2,695,505
8,420
88,452
47,216
11,123
8,988
8,149
66,326
48,697
—
9,872
164,199
133,044
255,708
118,861
16,298
390,867
239,035
115,127
17,896
372,058
$ 3,376,278
$ 3,200,607
52
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, 65,685,615 and
65,709,819 shares issued, and 137,017 and 118,834 restricted shares, respectively
Capital in excess of stated value
Retained earnings
Accumulated other comprehensive loss, net of tax
$
Treasury stock, 25,304,914 and 25,384,834 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,
2016
2015
$
65,823
322,643
1,114,561
(7,116)
1,495,911
(421,515)
1,074,396
1,195,513
2,269,909
65,829
320,073
1,067,396
(13,914)
1,439,384
(422,846)
1,016,538
1,122,660
2,139,198
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
—
141,738
59,978
30,351
12,649
4,023
28,325
277,064
495,237
90,527
54,553
81,621
24,303
38,104
784,345
Total capitalization and liabilities
$ 3,376,278
$ 3,200,607
See accompanying notes to financial statements.
53
EL PASO ELECTRIC COMPANY
STATEMENTS OF OPERATIONS
(In thousands except for share data)
Years Ended December 31,
2016
2015
2014
$
886,936
$
849,869
$
917,525
173,738
59,727
233,465
653,471
188,400
53,545
241,945
607,924
251,005
64,804
315,809
601,716
242,014
242,950
238,832
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
$
$
$
$
65,629
83,342
62,750
450,553
151,163
14,662
13,633
4,075
(4,199)
28,171
59,028
1,250
(5,092)
(8,368)
46,818
132,516
41,088
91,428
2.27
2.27
1.105
40,350,688
40,274,986
40,190,991
40,408,033
40,308,562
40,211,717
$
$
$
$
Operating revenues
Energy expenses:
Fuel
Purchased and interchanged power
Operating revenues net of energy expenses
Other operating expenses:
Other operations
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.
54
EL PASO ELECTRIC COMPANY
STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)
Net income
Other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs:
Net gain (loss) arising during period
Prior service benefit
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 benefit (expense)
Other comprehensive income (loss), net of tax
Comprehensive income
See accompanying notes to financial statements.
Years Ended December 31,
2016
2015
2014
$
96,768
$
81,918
$
91,428
(20,053)
32,697
5,429
824
(54,328)
34,200
(7,407)
4,965
8,444
(7,640)
498
11,504
(4,261)
(106)
(339)
(4,706)
6,798
$
103,566
$
(6,574)
8,622
(2,906)
(11,114)
(7,659)
6,182
10,827
(7,350)
467
(5,252)
438
(17,690)
(3,286)
2,828
(203)
(661)
(5,913)
76,005
$
8,051
(760)
(214)
7,077
(10,613)
80,815
55
EL PASO ELECTRIC COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(In thousands except for share data)
Common Stock
Shares
65,759,625
Amount
$
65,760
Capital in
Excess of
Stated Value
314,443
$
Accumulated
Other
Comprehensive
Income (Loss),
Net of Tax
Retained
Earnings
$
985,665
$
2,612
103,672
(4,696)
(19,162)
10,104
104
(5)
(19)
10
4,175
(183)
(302)
382
Treasury Stock
Shares
25,492,919
$
Amount
(424,647) $
Common
Stock Equity
943,833
Balances at December 31, 2013
Restricted common stock grants and deferred
compensation
Stock awards withheld for taxes
Forfeited restricted common stock
Deferred taxes on stock incentive plan
Compensation paid in shares
Net income
Other comprehensive income (loss)
Dividends declared
4,279
(188)
(19)
(302)
392
91,428
(10,613)
(44,556)
984,254
3,829
(571)
(26)
(475)
581
81,918
(5,913)
(47,059)
1,016,538
Balances at December 31, 2014
65,849,543
65,850
318,515
Restricted common stock grants and deferred
compensation
Stock awards withheld for taxes
Forfeited restricted common stock
Deferred taxes on stock incentive plan
Compensation paid in shares
Net income
Other comprehensive income (loss)
Dividends declared
6,356
(15,031)
(12,215)
6
(15)
(12)
2,266
(556)
(475)
323
Balances at December 31, 2015
65,828,653
65,829
320,073
91,428
(44,556)
1,032,537
81,918
(47,059)
1,067,396
(10,613)
(8,001)
25,492,919
(424,647)
(93,455)
1,557
871
(15,501)
(14)
258
(5,913)
(13,914)
25,384,834
(422,846)
Restricted common stock grants and deferred
compensation
Stock awards withheld for taxes
Forfeited restricted common stock
Deferred taxes on stock incentive plan
Compensation paid in shares
Net income
Other comprehensive income (loss)
Dividends declared
(5,723)
(298)
(6)
3,017
(261)
(364)
178
(74,181)
197
(5,936)
96,768
(49,603)
$ 1,114,561
$
6,798
(7,116)
25,304,914
$
(3)
1,235
4,252
(267)
(3)
(364)
277
96,768
6,798
(49,603)
(421,515) $ 1,074,396
99
Balances at December 31, 2016
65,822,632
$
65,823
$
322,643
See accompanying notes to financial statements.
56
EL PASO ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31,
2016
2015
2014
$
96,768
$
81,918
$
91,428
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
83,342
43,864
39,129
(14,662)
18,380
(2,092)
(7,350)
(93)
(5,815)
(786)
(3,121)
(2,750)
9,684
(2,209)
1,198
(4,807)
243,340
(225,361)
(42,383)
(281,458)
(41,966)
(277,078)
(37,877)
(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)
(23,030)
(5,092)
14,662
(117,675)
108,311
2,395
4,192
(331,192)
(49,603)
(47,059)
(44,556)
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
$
8,420
$
8,149
$
231,399
(231,219)
—
149,468
(2,328)
102,764
14,912
25,592
40,504
Cash Flows From Operating Activities:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service
Amortization of nuclear fuel
Deferred income taxes, net
Allowance for equity funds used during construction
Other amortization and accretion
Gain on sale of property, plant and equipment
Net gains on sale of decommissioning trust funds
Other operating activities
Change in:
Accounts receivable
Inventories
Net over-collection (under-collection) of fuel revenues
Prepayments and other
Accounts payable
Taxes accrued
Other current liabilities
Deferred charges and credits
Net cash provided by operating activities
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment
Cash additions to nuclear fuel
Capitalized interest and AFUDC:
Utility property, plant and equipment
Nuclear fuel
Allowance for equity funds used during construction
Decommissioning trust funds:
Purchases, including funding of $4.5 million
Sales and maturities
Proceeds from sale of property, plant and equipment
Other investing activities
Net cash used for investing activities
Cash Flows From Financing Activities:
Dividends paid
Borrowings under the revolving credit facility:
Proceeds
Payments
Payment on maturing RGRT senior notes
Proceeds from issuance of senior notes
Other financing activities
Net cash provided by financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
See accompanying notes to financial statements.
57
INDEX TO NOTES TO FINANCIAL STATEMENTS
Note A. Summary of Significant Accounting Policies
Note B. New Accounting Standards
Note C. Regulation
Note D. Regulatory Assets and Liabilities
Note E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant
Note F. Accounting for Asset Retirement Obligations
Note G. Common Stock
Note H. Accumulated Other Comprehensive Income (Loss)
Note I. Long-Term Debt and Financing Obligations
Note J. Income Taxes
Note K. Commitments, Contingencies and Uncertainties
Note L. Litigation
Note M. Employee Benefits
Note N. Franchises and Significant Customers
Note O. Financial Instruments and Investments
Note P. Supplemental Statements of Cash Flow Disclosures
Note Q. Selected Quarterly Financial Data (Unaudited)
Page
59
62
63
68
69
72
73
78
80
82
85
87
88
101
102
107
108
58
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
A.
Summary of Significant Accounting Policies
General. El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity
in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a full
requirements wholesale customer in Texas.
Basis of Presentation. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed
by the Federal Energy Regulatory Commission (the "FERC").
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting
period. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue,
income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). Actual results
could differ from those estimates.
Application of the Financial Accounting Standards Board (the "FASB") Guidance for Regulated Operations. Regulated
electric utilities typically prepare their financial statements in accordance with the FASB guidance for regulated operations. The
FASB guidance for regulated operations requires the Company to include an allowance for equity and borrowed funds used during
construction ("AEFUDC" and "ABFUDC") as a cost of construction of electric plant in service. AEFUDC is recognized as income
and ABFUDC is shown as capitalized interest charges in the Company’s statements of operations. The FASB guidance for regulated
operations also requires the Company to show certain recoverable costs as either assets or liabilities on a utility’s balance sheet if
the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already
permitted such cost recovery) or will be credited or refunded to the utility’s customers. The resulting regulatory assets or liabilities
are amortized in subsequent periods based upon the respective amortization periods reflected in a utility’s regulated rates. See Part
II, Item 8, Financial Statements and Supplementary Data, Note D. The Company applies the FASB guidance for regulated operations
for all three of the jurisdictions in which it operates.
Comprehensive Income. Certain gains and losses that are not recognized currently in the statements of operations are reported
as other comprehensive income in accordance with the FASB guidance for reporting comprehensive income.
Utility Plant. Utility plant is generally reported at cost. The cost of renewals and betterments are capitalized and the costs
of repairs and minor replacements are charged to the appropriate operating expense accounts. Depreciation is provided on a straight-
line basis over the estimated remaining lives of the assets (ranging in average from 5 to 48 years). The average composite depreciation
rate utilized in 2016, 2015 and 2014 was 2.28%, 2.64%, and 2.60%, respectively. When property subject to composite depreciation
is retired or otherwise disposed of in the normal course of business, its cost together with the cost of removal, less salvage is
charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed
from the balance sheet accounts and a gain or loss is recognized. During 2016, depreciation and amortization decreased due to
changes in depreciation rates approved in the most recent final orders from the Public Utility Commission of Texas ("PUCT") and
the New Mexico Public Regulation Commission ("NMPRC") and changes in the estimated life of certain intangible software
assets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note E.
Previously, the Company recorded gains and losses on the disposition of vehicles in earnings when realized. However,
beginning in 2016, the Company began crediting the proceeds (salvage) on the disposition of vehicles to accumulated depreciation.
The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. The Company is also amortizing its
share of costs associated with on-site spent fuel storage casks at Palo Verde Nuclear Generating Station ("Palo Verde") over the
burn period of the fuel that will necessitate the use of the storage casks. See Part II, Item 8, Financial Statements and Supplementary
Data, Note E.
Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used
is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be
generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment
charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.
59
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
AFUDC and Capitalized Interest. The Company capitalizes interest ("ABFUDC") and common equity ("AEFUDC") costs
to construction work in progress and capitalizes interest to nuclear fuel in process in accordance with the FERC Uniform System
of Accounts as provided for in the FASB guidance. AFUDC is a non-cash component of income and is calculated monthly and
charged to all new eligible construction and capital improvement projects. AFUDC is compounded on a semi-annual basis. The
average AFUDC rates used in 2016, 2015 and 2014 were 6.43%, 7.18% and 8.15%, respectively.
Asset Retirement Obligation. The FASB guidance sets forth accounting requirements for the recognition and measurement
of liabilities associated with the retirement of tangible long-lived assets. An ARO associated with long-lived assets included within
the scope of the FASB guidance is that for which a legal obligation exists under enacted laws, statutes, written or oral contracts,
including obligations arising under the doctrine of promissory estoppel and legal obligations to perform an asset retirement activity
even if the timing and/or settlement are conditioned on a future event that may or may not be within the control of an entity. See
Part II, Item 8, Financial Statements and Supplementary Data, Note F. Under the FASB guidance, these liabilities are recognized
as incurred if a reasonable estimate of fair value can be established and are capitalized as part of the cost of the related tangible
long-lived assets. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion
expense).
Cash and Cash Equivalents. All temporary cash investments with an original maturity of three months or less are considered
cash equivalents.
Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheet, are reported
at fair value and consist of cash, equity securities and municipal, federal and corporate bonds in trust funds established for
decommissioning of its interest in Palo Verde. Such marketable securities are classified as "available-for-sale" securities and, as
such, unrealized gains and losses are included in accumulated other comprehensive loss as a separate component of common stock
equity. However, if declines in the fair value of marketable securities below original cost basis are determined to be other than
temporary, the declines are reported as losses in the statements of operations and a new cost basis is established for the affected
securities at fair value. Gains and losses are determined using the cost of the security based on the specific identification basis.
See Part II, Item 8, Financial Statements and Supplementary Data, Note O.
Derivative Accounting. Accounting for derivative instruments and hedging activities requires the recognition of derivatives
as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value
of these instruments are recorded in earnings or other comprehensive income. See Part II, Item 8, Financial Statements and
Supplementary Data, Note O.
Inventories. Inventories, primarily parts, materials, supplies, fuel oil and natural gas are stated at average cost, which is not
to exceed recoverable cost.
Operating Revenues Net of Energy Expenses. The Company accrues revenues for services rendered, including unbilled
electric service revenues. Energy expenses are stated at actual cost incurred. The Company’s Texas retail customers are billed
under base rates and a fixed fuel factor approved by the PUCT. The Company’s New Mexico retail customers are billed under
base rates and a fuel adjustment clause which is adjusted monthly, as approved by the NMPRC. The Company's FERC sales for
resale customers are billed under formula base rates and fuel factors and a fuel adjustment clause which is adjusted monthly. The
Company’s recovery of energy expenses is subject to periodic reconciliations of actual energy expenses incurred to actual fuel
revenues collected. The difference between energy expenses incurred and fuel revenues charged to customers is reflected as over/
under-collection of fuel revenues in the balance sheets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.
Revenues. Revenues related to the sale of electricity are recorded when service is provided or electricity is delivered to
customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic
basis throughout the month. Unbilled revenues are recorded for estimated amounts of energy delivered in the period following
the customers billing cycle to the end of the month. Unbilled revenues are estimated based on monthly generation volumes and
by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included
accrued unbilled revenues of $21.0 million and $21.7 million as of December 31, 2016 and 2015, respectively. The Company
presents revenues net of sales taxes in its statements of operations.
Allowance for Doubtful Accounts. The allowance for doubtful accounts represents the Company’s estimate of existing
accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to
various classes of outstanding receivables. The write-off factors used to estimate uncollectible accounts are based upon
consideration of both historical collections experience and management’s best estimate of future collections success given the
60
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
existing collections environment. Additions, deductions and balances for allowance for doubtful accounts for 2016, 2015 and 2014
are as follows (in thousands):
Balance at beginning of year
Additions:
Charged to costs and expense
Recovery of previous write-offs
Uncollectible receivables written off
Balance at end of year
2016
2015
2014
$
2,046
$
2,253
$
2,261
2,427
1,395
3,712
2,156
$
2,057
1,613
3,877
2,046
$
2,755
1,516
4,279
2,253
$
Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting
for income taxes. Deferred income taxes are recognized for the estimated future tax consequences of "temporary differences" by
applying enacted statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial
statement carrying amounts and the tax basis of existing assets and liabilities. Historically, certain temporary differences are
accorded flow-through treatment by the Company's regulators and impact the Company's effective tax rate. The FASB guidance
requires that rate-regulated companies record deferred income taxes for temporary differences accorded flow-through treatment
at the direction of the regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash
flow to be reflected in future rates. Because the Company's regulators have consistently permitted the recovery of tax effects
previously flowed-through earnings, the Company has recorded regulatory liabilities and assets offsetting such deferred tax assets
and liabilities. During the third quarter of 2016, the Company changed its accounting for state income taxes from the flow-through
method to the normalization method in accordance with the final orders from the PUCT and the NMPRC in its 2015 rate cases,
effective January 1, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C for further discussion. The
effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment
date. The Company recognizes tax assets and liabilities for uncertain tax positions in accordance with the recognition and
measurement criteria of the FASB guidance for uncertainty in income taxes. See Part II, Item 8, Financial Statements and
Supplementary Data, Note J.
Earnings per Share. The Company’s restricted stock awards are participating securities and earnings per share must be
calculated using the two-class method in both the basic and diluted earnings per share calculations. For the basic earnings per
share calculation, net income is allocated to the weighted average number of restricted stock awards and to the weighted average
number of shares outstanding. The net income allocated to the weighted average number of shares outstanding is then divided by
the weighted average number of shares outstanding to derive the basic earnings per share. For the diluted earnings per share, net
income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares and
dilutive potential shares outstanding. The Company’s dilutive potential shares outstanding amount is calculated using the treasury
stock method for the unvested performance shares. Net income allocated to the weighted average number of shares and dilutive
potential shares is then divided by the weighted average number of shares and dilutive potential shares outstanding to derive the
diluted earnings per share. See Part II, Item 8, Financial Statements and Supplementary Data, Note G.
Stock-Based Compensation. The Company has a stock-based long-term incentive plan. The Company is required under the
FASB guidance to measure the cost of employee services received in exchange for an award of equity instruments based on the
grant-date fair value of the award. Such costs are recognized over the period during which an employee is required to provide
service in exchange for the award (the "requisite service period") which typically is the vesting period. Compensation cost is not
recognized for anticipated forfeitures prior to vesting of equity instruments. See Part II, Item 8, Financial Statements and
Supplementary Data, Note G.
Pension and Post-retirement Benefit Accounting. See Part II, Item 8, Financial Statements and Supplementary Data, Note
M for a discussion of the Company’s accounting policies for its employee benefits.
Reclassification. Certain amounts in the Company's financial statements for 2015 have been reclassified to conform to the
2016 presentation. The Company implemented Accounting Standards Update ("ASU") 2015-03 and ASU 2015-17 in the first
quarter of 2016, retrospectively to all periods presented in the Company's financial statements. See Part II, Item 8, Financial
Statements and Supplementary Data, Note I and Note O for impact of ASU 2015-03, and Note J for impact of ASU 2015-17.
61
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
B.
New Accounting Standards
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. Early adoption of ASU 2014-09 is permitted after December 15, 2016, however,
the Company plans to adopt the new standard for reporting periods beginning after December 15, 2017.
Under the new standard, companies may use either of the following transition methods: (i) a full retrospective approach
reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii)
a modified retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption
(which includes additional footnote disclosures). The Company has not concluded which transition method it will elect but it
currently anticipates using the modified retrospective approach.
The Company is currently in the process of evaluating the impact of the new standard on its various revenue and cash flow
streams, including the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition
and disclosure under the new guidance. Tariff sales to customers are determined to be in the scope of the new standard and
represent a significant portion of the Company’s total operating revenues. The Company has not completed its final evaluation of
tariff sales under the new guidance but currently does not anticipate that ASU 2014-09 will have a material impact on the Company's
revenue recognition for such sales. The Company is still considering the impacts of the guidance on several industry-related
accounting issues, including the accounting for contributions in aid of construction ("CIAC"), assessing the collectability criterion
and the presentation of revenues associated with alternative revenue programs. The Company's initial assessment may change as
we execute our implementation plan and new guidance is provided by the American Institute of Certified Public Accountants
Power and Utilities Industry Task Force.
In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and
Measurement of Financial Assets and Liabilities to enhance the reporting model for financial instruments by addressing certain
aspects of recognition, measurement, presentation, and disclosure. ASU 2016-01 generally requires entities to measure equity
investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any
changes in fair value in net income. The guidance for classifying and measuring investments in debt securities and loans is not
changed by this ASU, but requires entities to record changes in other comprehensive income. Financial assets and financial liabilities
must be separately presented by measurement category on the balance sheet or in the accompanying notes to the financial statements.
ASU 2016-01 clarifies the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in
combination with the entity's other deferred tax assets. The provisions of this ASU become effective for public companies for
fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Upon adoption of the new
standard, the Company expects to record the cumulative effects as of January 1, 2018 which will result in an adjustment to
accumulated other comprehensive income (losses) and retained earnings for unrealized gains (losses) related to equity securities
owned by the Company. Had the Company been required to adopt the new standard at January 1, 2016, accumulated other
comprehensive income would decrease by $28.8 million and retained earnings would increase by a corresponding amount.
Furthermore, the Company would report for the year ended December 31, 2016 an increase in investment income of $1.2 million,
an increase in income tax expense of $0.2 million and a decrease in other comprehensive income of $1.0 million. The Company
is continuing to assess the future impact of this ASU.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among
organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring qualitative and quantitative
disclosures on leasing agreements. ASU 2016-02 maintains a distinction between finance leases and operating leases similar to
the distinction under previous leases guidance for capital leases and operating leases. The impact of leases reported in the Company's
operating results and statement of cash flows are expected to be similar to previous GAAP. ASU 2016-02 requires the recognition
in the statement of financial position, by the lessee, of a liability to make lease payments (the lease liability) and a right-of-use
asset representing its right to use the underlying asset for the lease term. How leases are recorded in regard to financial position
represents a significant change from previous GAAP guidance. The lessee is permitted to make an accounting policy election to
not recognize lease assets and lease liabilities for short-term leases. Implementation of the standard for public companies will be
required for annual reporting periods beginning after December 15, 2018 and interim periods within that reporting period. Early
adoption of ASU 2016-02 is permitted for all entities, however, the Company plans to adopt the new standard for reporting periods
62
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
beginning after December 15, 2018. Adoption of the new lease accounting standard will require the Company to apply the new
standard to the earliest period using a modified retrospective approach. The Company is currently in the process of evaluating the
impact of the new standard, including the evaluation of the impact, if any, on changes to business processes, systems and controls
to support recognition and disclosure under the new guidance, however, at this time is unable to determine the impact this standard
will have on the financial statements and related disclosures.
In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718) Improvements to Employee
Share-Based Payment Accounting to simplify the accounting for share-based payment transactions, including the income tax
consequences, classification of awards either as equity or liabilities, and classification on the statements of cash flows. The Company
will adopt the new standard effective January 1, 2017 and does not expect the effect of the adoption to be material to the Company's
financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard will be to increase
net operating loss carryforward deferred tax assets and retained earnings by approximately $0.2 million on January 1, 2017. The
Company also expects to continue to account for its outstanding stock awards based on the equity method and therefore does not
anticipate any changes in reporting related compensation expense.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326) ("ASU 2016-13"). ASU
2016-13 changes how companies measure and recognize credit impairment for many financial assets. The new current expected
credit loss model will require companies to immediately recognize an estimate of credit losses expected to occur over the remaining
life of the financial assets that are in the scope of the standard. The ASU also makes targeted amendments to the current impairment
model for available-for-sale debt securities. For public business entities, the provisions of ASU 2016-13 are effective for fiscal
years and interim periods within that reporting period beginning after December 15, 2019. Early implementation is permitted as
of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-13 will be
applied in a modified-retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of
the first reporting period in which the guidance is implemented. The Company is currently assessing the future impact of ASU
2016-13.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts
and Cash Payments to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement
of cash flows. The new guidance addresses the following classification issues: debt prepayment or debt extinguishment costs;
settlement of zero-coupon bonds; contingent consideration payments made after a business combination; proceeds from the
settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies, including bank-owned
life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and
separately identifiable cash flows and application of the predominance principle. For public business entities, the provisions of
ASU 2016-15 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2017.
Early adoption is permitted, including adoption in an interim period. If an entity elects early adoption of ASU 2016-15 in an interim
period, adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects
early adoption must adopt all of the amendments in the same period. ASU 2016-15 will be applied using a retrospective transition
method to each period presented. If it is impracticable to apply ASU 2016-15 retrospectively for some of the issues, the amendments
for those issues may be applied prospectively as of the earliest date practicable. The Company is currently assessing the future
impact of this ASU.
In December 2016, the FASB issued ASU 2016-19, Technical Corrections and Improvements, which amends a number of
Topics in the FASB ASC. This ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive
technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or
create a significant administrative cost to most entities. Most of the amendments are effective upon issuance of ASU 2016-19
while certain amendments that require transition guidance are effective for the Company beginning January 1, 2017. The Company
believes it is in compliance with those amendments that are effective immediately and that are applicable to the Company. The
Company has not completed its evaluation of the new standard for amendments that require transition guidance.
C.
Regulation
General
The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC and
the FERC. Municipal orders, ordinances and other agreements regarding rates and services adopted by Texas municipalities are
subject to review and approval by the PUCT. The FERC has jurisdiction over the Company's wholesale (sales for resale) transactions,
63
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and
the FERC are subject to judicial review.
Texas Regulatory Matters
2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities
incorporated in its Texas service territory, and the PUCT in Docket No. 44941, a request for an annual increase in non-fuel base
revenues (the "2015 Texas Retail Rate Case").
On July 21, 2016, the parties to PUCT Docket No. 44941 filed the Joint Motion to Implement Uncontested Amended and
Restated Stipulation and Agreement which was unopposed by the parties (the "Unopposed Settlement"). On August 25, 2016, the
PUCT approved the Unopposed Settlement and issued its final order in Docket No. 44941 (the "PUCT Final Order"), as proposed.
The PUCT Final Order provided for: (i) an annual non-fuel base rate increase, lower annual depreciation expense, a revised return
on equity for AFUDC purposes, and the inclusion of substantially all new plant in service in rate base; (ii) an additional annual
non-fuel base rate increase of $3.7 million related to Four Corners Generating Station ("Four Corners") costs, which will be
collected through a surcharge terminating on July 12, 2017; (iii) removing the separate rate treatment for residential customers
with solar systems that the Company had proposed in its August 10, 2015 filing; (iv) allowing the Company to recover $3.1 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 PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the
cumulative effect of the PUCT Final Order which related back to January 12, 2016.
2017 Texas Retail Rate Case Filing. On February 13, 2017, the Company filed with the City of El Paso, other municipalities
incorporated in the Company's Texas service territory and the PUCT in Docket No.46831, a request for an increase in non-fuel
base revenues of approximately $42.5 million. The Company invoked its statutory right to have its new rates relate back for
consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed
will be surcharged or refunded to customers after the PUCT's final order in Docket No. 46831. The PUCT has the authority to
require the Company to surcharge or refund such difference over a period not to exceed 18 months. The Company cannot predict
the outcome or the timing of this rate case at this time.
Energy Efficiency Cost Recovery Factor. On May 1, 2015, the Company filed its annual application to establish its energy
efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and a true-up to prior year actual
costs, the Company requested approval of a $1.0 million bonus for the 2014 energy efficiency program results in accordance with
PUCT rules. This case was assigned PUCT Docket No. 44677. A stipulation and settlement agreement was filed September 24,
2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT included a performance
bonus of $1.0 million. The Company recorded the performance bonus in operating revenues in the fourth quarter of 2015.
On April 29, 2016, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2017.
In addition to projected energy efficiency costs for 2017 and true-up to prior year actual costs, the Company requested approval
of a $0.7 million bonus for the 2015 energy efficiency program results in accordance with PUCT rules. This case was assigned
PUCT Docket No. 45885. Parties in the proceeding, including PUCT staff and the City of El Paso, filed a settlement in the case
that approved the Company's proposal with a reduction to the 2015 program bonus of $0.2 million. The PUCT approved the
settlement on October 28, 2016. The settlement approved by the PUCT included a performance bonus of $0.5 million which was
recorded in operating revenues in the third quarter of 2016.
Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered
from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows
the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon
the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires
the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount
and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to
64
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery
to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the
previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT
in fuel reconciliation proceedings.
On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor
by approximately 24% to reflect reduced fuel expenses primarily related to a reduction in the price of natural gas used to generate
power. The over-recovered balance was below the PUCT's materiality threshold. The reduction in the fixed fuel factor was effective
on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015.
On November 30, 2016, the Company filed a request, which was assigned PUCT Docket No. 46610, to increase its fixed
fuel factor by 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 December 31, 2016, the Company had under-recovered fuel costs in the amount of $11.1
million for the Texas jurisdiction.
Fuel Reconciliation Proceeding. On September 27, 2016, the Company filed an application with the PUCT, designated as
PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of
April 1, 2013 through March 31, 2016. A procedural schedule has been adopted with hearings in April 2017. As of December 31,
2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $114.4
million. The Company cannot predict the outcome or the timing of this matter.
Montana Power Station Approvals. The Company received Certificate of Convenience and Necessity ("CCN") approval
from the PUCT to construct four natural gas fired generating units at Montana Power Station ("MPS") in El Paso County, Texas.
The Company also obtained air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the U.S.
Environmental Protection Agency (the "EPA"). MPS Units 1 and 2 and associated transmission lines and common facilities were
completed and placed into service in March 2015. MPS Units 3 and 4 were completed and placed into service on May 3, 2016
and September 15, 2016, respectively.
Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program that
includes the construction and ownership of a 3 MW solar photovoltaic system located at MPS. Participation will be on a voluntary
basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT
Docket No. 44800. The Company filed a settlement agreement among all parties on July 1, 2016 approving the program, and the
PUCT approved the settlement agreement and program on September 1, 2016. The Company expects completion of the solar
facility and commencement of the program in the second quarter of 2017.
Four Corners. On February 17, 2015, the Company and Arizona Public Service Company ("APS") entered into an asset
purchase agreement (the "Purchase and Sale Agreement") providing for the sale of the Company's interest in Four Corners to APS.
The sale of the Company's interest in Four Corners closed 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 has been subject to numerous procedural matters, including a March 23, 2016
order in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the
requested rate and accounting findings, including mine reclamation costs, in a rate case proceeding. On September 1, 2016, a
motion by parties in the proceeding to suspend the procedural schedule in order to pursue settlement was approved, and the parties
are engaged in settlement discussions.
At December 31, 2016, the regulatory asset associated with the Four Corners mine reclamation costs for the Company's
Texas jurisdiction was approximately $7.3 million. The Company currently continues to recover its mine reclamation costs in
Texas under previous orders and decisions of the PUCT. If any future determinations made by the Company's regulators result in
changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes
would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions.
Other Required Approvals. The Company has obtained other required approvals for tariffs and approvals required by the
Public Utility Regulatory Act (the "PURA") and the PUCT.
65
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
New Mexico Regulatory Matters
2015 New Mexico Rate Case Filing. On May 11, 2015, the Company filed 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.
Fuel and Purchased Power Costs. On January 8, 2014, the NMPRC approved the continuation of the Fuel and Purchased
Power Cost Adjustment Clause (the "FPPCAC") without modification in NMPRC Case No. 13-00380-UT. Historically, fuel and
purchased power costs were recovered through base rates and a FPPCAC that accounts for changes in the costs of fuel relative to
the amount included in base rates. Effective July 1, 2016, with the implementation of the final order in Case No. 15-00127-UT,
fuel and purchased power costs are no longer recovered through base rates but are recovered through the FPPCAC. Fuel and
purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second
succeeding month. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the
FPPCAC as purchased power using a proxy market price approved in Case No. 13-00380-UT. The Company's request to reconcile
its fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in Case No. 15-00127-
UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2016 that
total approximately $114.6 million. At December 31, 2016, the Company had a net fuel over-recovery balance of $0.2 million in
New Mexico.
Montana Power Station Approvals. The Company received CCNs from the NMPRC to construct four units at MPS and the
associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the EPA. A final order in
NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and
associated transmission lines and common facilities were completed and placed into service in March 2015. MPS Units 3 and 4
were completed and placed into service on May 3, 2016 and September 15, 2016, respectively.
Four Corners. On June 15, 2016, in NMPRC Case No. 15-00109-UT, the NMPRC issued its final order approving the
Company's sale and abandonment of its ownership interest in Four Corners to APS pursuant to a February 17, 2015 Purchase and
Sale Agreement between the Company and APS. See Part II, Item 8, Financial Statements and Supplementary Data, Note E for
further details on the sale of Four Corners.
5 MW Holloman Air Force Base ("HAFB") Facility CCN. On October 7, 2015, in NMPRC Case No. 15-00185-UT, the
NMPRC issued a final order approving a CCN for 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 special retail contract, which includes power sales agreement
for the facility, to replace the existing load retention agreement which was approved by final order issued October 5, 2016 in
NMPRC Case No. 16-00224-UT. Construction of the solar generation facility is expected to be completed in the second quarter
of 2017.
Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case
No. 15-00280-UT to issue up to $310.0 million of new long-term debt and to guarantee the issuance of up to $65.0 million of new
debt by Rio Grande Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel
debt obligations. This approval supersedes prior approvals. Under this authorization, on March 24, 2016, the Company issued
$150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044. The net proceeds from the issuance of
these senior notes, after deducting the underwriters' commission, were $158.1 million. These proceeds include accrued interest of
$2.4 million and a $7.1 million premium before expenses. These senior notes constitute an additional issuance of the Company's
5.00% Senior Notes due 2044, of which $150.0 million was previously issued on December 1, 2014, for a total principal amount
outstanding of $300.0 million.
Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions,
recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC.
66
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Federal Regulatory Matters
Four Corners. On June 26, 2015, APS filed an application requesting authorization from FERC to purchase 100% of the
Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and
rights. On December 22, 2015, FERC issued an order approving the proposed transaction. 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.
Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an
order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under the revolving credit facility
("RCF") up to $400.0 million outstanding at any time, to issue up to $310.0 million in long-term debt, and to guarantee the issuance
of up to $65.0 million of new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective
from November 15, 2015 through November 15, 2017. This approval supersedes prior approvals.
Under this authorization, on March 24, 2016, the Company issued $150.0 million aggregate principal amount of 5.00%
Senior Notes due December 1, 2044. Additionally under this authorization, on January 9, 2017, the Company exercised its option
to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50.0 million to $350.0
million. The Company still has the option to extend the facility by one additional year to January 2021 and to increase the RCF
by up to $50.0 million (up to a total of $400.0 million) upon the satisfaction of certain conditions, more fully set forth in the
agreement, including obtaining commitments from lenders or third party financial institutions. Additionally, the Company agreed
to reduce the letters of credit commitment to $50.0 million from a total commitment, under the RCF, of $350.0 million.
Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and
other approvals as required by the FERC.
United States Department of Energy ("DOE"). The DOE regulates the Company's exports of power to the Comisión Federal
de Electricidad in Mexico pursuant to a license and two presidential permits issued by the DOE.
The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's
uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Part II, Item 8, Financial Statements
and Supplementary Data, Note E for discussion of spent fuel storage and disposal costs.
Sales for Resale
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.
67
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,
2016
December 31,
2015
Regulatory assets
Regulatory tax assets (a)
Loss on reacquired debt (c)
Final coal reclamation (d)
Nuclear fuel postload daily financing charge
Unrecovered issuance costs due to reissuance of PCBs (c)
Texas energy efficiency
Texas 2015 rate case costs
Texas 2017 rate case costs
Texas relate back surcharge
New Mexico renewable energy credits and related costs (i)
New Mexico 2010 FPPCAC audit
New Mexico Palo Verde deferred depreciation
New Mexico 2015 rate case costs
New Mexico 2017 rate case costs
Total regulatory assets
Regulatory liabilities
Regulatory tax liabilities (a)
Accumulated deferred investment tax credit (j)
Texas energy efficiency
New Mexico energy efficiency
Texas military base discount and recovery factor
New Mexico gain on sale of assets (l)
Total regulatory liabilities
(b)
May 2035
(e)
(e)
August 2042
(f)
September 2018
(g)
(h)
June 2022
June 2019
(b)
June 2019
(g)
(b)
(b)
(f)
(f)
(k)
June 2019
$
$
$
$
66,670
15,780
9,581
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
$
$
$
$
69,359
16,632
9,520
4,195
827
25
1,882
—
—
6,397
434
4,568
1,288
—
115,127
17,266
4,011
—
2,238
788
—
24,303
______________________________
(a) We do not earn a return on these items since the related accumulated deferred income tax assets and liabilities offset.
(b) The amortization periods for these assets and liabilities are based upon the life of the associated assets or liabilities.
(c) This item is recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance.
(d) This item relates to coal reclamation costs associated with Four Corners. See Part II, Item 8, Financial Statements and
Supplementary Data, Note C.
(e) This item is recovered through fuel recovery mechanisms established by tariffs.
(f)
This item is recovered or credited through a recovery factor that is set annually.
(g) Amortization period is anticipated to be established in next general rate case.
(h) This item relates to the recovery of revenues through a separate surcharge beginning October 1, 2016 and ending September
(i)
30, 2017. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.
This item relates to renewable energy credits and procurement plan costs, components approved for recovery in the New
Mexico 2015 rate case.
This item is excluded from rate base.
(j)
(k) This item represents the net asset/net liability related to the military discount which is recovered from non-military customers
(l)
through a recovery factor that is set annually.
This item relates to the gains on the sales of assets the Company shares with its New Mexico customers over a three year
period.
68
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, 2016 (in thousands):
Nuclear production
Steam and other
Total production
Transmission
Distribution
General
Intangible
Total
$
Gross
Plant
948,382
926,419
1,874,801
498,660
1,127,897
205,866
84,342
$ 3,791,566
$
Accumulated
Depreciation
Net
Plant
628,382
739,880
1,368,262
239,172
762,296
148,626
28,878
$ (1,244,332) $ 2,547,234
(320,000) $
(186,539)
(506,539)
(259,488)
(365,601)
(57,240)
(55,464)
During 2016, depreciation decreased due to changes in rates approved in the PUCT Final Order and the NMPRC Final Order.
The change, effective in January 2016 for Texas and July 2016 for New Mexico, reduced depreciation expense in 2016 by $10.9
million.
Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset
(ranging from 3 to 15 years). Effective July 2015, the Company changed the estimated useful life of certain large intangible
software systems which decreased depreciation during 2015 by $1.8 million. The table below presents the actual and estimated
amortization expense for intangible plant for the previous three years and for the next five years (in thousands):
2014
2015
2016
2017 (estimated)
2018 (estimated)
2019 (estimated)
2020 (estimated)
2021 (estimated)
$
8,051
6,482
5,302
5,148
4,631
4,242
3,808
3,227
The Company owns a 15.8% interest in each of the three nuclear generating units and common facilities at Palo Verde, in
Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison
Company ("SCE"), PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power
District ("SRP") and the Los Angeles Department of Water and Power.
A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2016
and 2015 is as follows (in thousands):
Electric plant in service
Accumulated depreciation
Construction work in progress
Total
December 31, 2016
December 31, 2015
Palo Verde
Other (a)
Palo Verde
Other (a)
$
$
948,382
(320,000)
50,598
678,980
$
$
67,621
(44,377)
1,895
25,139
$
$
917,483
(304,060)
48,938
662,361
$
$
229,627
(181,886)
9,528
57,269
_______________
(a) 2015 other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners and certain other transmission
facilities which the Company sold on July 6, 2016.
69
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, 2016, the Company’s decommissioning trust fund had a balance of $255.7 million, which is above its minimum
funding level. The Company monitors the status of its decommissioning funds and adjusts its deposits, if necessary.
Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers
retained by APS. In December 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013
Study"). The 2013 Study estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover
its share of decommissioning costs which was an increase in decommissioning costs of $23.3 million (stated in 2013 dollars) from
the 2010 Palo Verde decommissioning study. However, because the cash flows from the 2013 Study were less than the inflated
amounts from the 2010 Study, the effect of this change lowered the ARO by $1.9 million which lowered annual expenses starting
in January 2014. Although the 2013 Study was based on the latest available information, there can be no assurance that
decommissioning cost estimates will not increase in the future or that regulatory requirements will not change. In addition, until
a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose of low-
level radioactive waste are subject to uncertainty. As provided in the ANPP Participation Agreement, the participants are required
to conduct a new decommissioning study every three years. A 2016 Palo Verde decommissioning study (the "2016 Study") is
underway and is expected to be finalized in the second quarter of 2017 at which time the Company will record its effects. If the
expected cash flows as identified in the 2016 Study exceed the expected cash flows identified in the 2013 Study (stated in 2016
dollars), the ARO will increase with a corresponding increase in the ARO asset. Under such circumstances, increases in Palo Verde
accretion expense and depreciation expense will occur. While the Company attempts to seek amounts in rates to meet its
decommissioning obligations, it is not able to conclude given the evidence available to it now that it is probable these costs will
continue to be collected over the period until decommissioning begins in 2044. The Company is ultimately responsible for these
costs and its future actions combined with future decisions from regulators will determine how successful the Company is in this
effort.
Spent Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"),
the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by
all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or
High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent
nuclear fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach
of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to accept Palo
70
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On August 18, 2014, APS and the DOE
entered into a settlement agreement stipulating to a dismissal of the lawsuit and payment of $57.4 million by the DOE to the Palo
Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On
October 8, 2014, the Company received approximately $9.1 million, representing its share of the award, of which $7.9 million
was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS, acting on behalf of itself
and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage
costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was $42.0 million. On June 1, 2015, the
Company received approximately $6.6 million, representing its share of the award, of which $5.8 million was credited to customers
through the applicable fuel adjustment clauses in March 2015. After June 2015, APS will file annual claims for the period July 1
of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period
July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. The Company's share
of this claim is approximately $1.9 million, of which $1.6 million was credited to customers through the applicable fuel adjustment
clauses in March 2016. On October 31, 2016 APS filed an $11.3 million claim for the period July 1, 2015 through June 30, 2016.
The Company's share of this claim is approximately $1.8 million. On February 1, 2017, the DOE notified APS of the approval of
the claim. Any reimbursement is anticipated to be received in the second quarter of 2017, and the majority of the award received
by the Company will be credited to customers through applicable fuel adjustment clauses.
DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations
by designing, licensing, constructing and operating a permanent geologic repository in Yucca Mountain, Nevada. In March 2010,
the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending
before the NRC. Several interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively
decided by the NRC or the courts. The Company cannot predict when spent fuel shipments to the DOE will commence.
Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear
fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has
sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation,
which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel
are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to
accommodate all of the fuel that will be irradiated during the period of extended operation.
Liability and Insurance Matters. The Palo Verde Participants have insurance for public liability resulting from nuclear energy
hazards to the full limit of liability under federal law, which is currently at $13.4 billion. This potential liability is covered by
primary liability insurance provided by commercial insurance carriers in the amount of $450.0 million, and the balance is covered
by an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the
accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per
incident basis. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately
$127.3 million, subject to an annual limit of $19.0 million. Based upon the Company's 15.8% interest in the three Palo Verde
units, the Company's maximum potential assessment per incident for all three units is approximately $60.4 million, with an annual
payment limitation of approximately $9.0 million.
The Palo Verde Participants maintain $2.75 billion of "all risk" nuclear property insurance. The insurance provides coverage
for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by
a release of radioactive material, the policy's coverage limit is $2.25 billion. The Company has also secured insurance against
portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen
outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy
conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies.
If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance
programs, the Company could be assessed retrospective premium adjustments of up to $12.9 million for the current policy period.
71
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Four Corners
On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the sale of the
Company’s interests in Four Corners to APS. Four Corners continued to provide energy to serve the Company's native load up to
the closing date of the sale on July 6, 2016. Also on July 6, 2016, prior to the closing of the transaction, the Company and APS
entered into an amendment to the Purchase and Sale Agreement pursuant to which APS assigned its right, title and interest in the
Purchase and Sale Agreement to its affiliate 4C Acquisition, LLC ("APS's affiliate"), and Pinnacle West Capital Corporation, the
parent company of APS and APS's affiliate ("Pinnacle West"), guaranteed APS's affiliate's obligations under the Purchase and Sale
Agreement. The sales price was $32.0 million, which was based on the net book value as defined in the Purchase and Sale
Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million, respectively, to reflect the assumption by
APS's affiliate of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses. The sales
price was also adjusted downward by approximately $1.3 million for estimated closing adjustments and other assets and liabilities
assumed by APS's affiliate. At the closing, the Company received approximately $4.2 million in cash, subject to post-closing
adjustments. No significant gain or loss was recorded after the closing date. APS's affiliate assumed responsibility for all Four
Corners capital expenditures made after July 6, 2016, which assumption is guaranteed by Pinnacle West. In addition, APS's affiliate
will indemnify the Company against certain liabilities and costs related to the future operation of Four Corners, which
indemnification is guaranteed by Pinnacle West. See Part II, Item 8, Financial Statements and Supplementary Data, Note C for a
discussion of regulatory filings associated with Four Corners.
F.
Accounting for Asset Retirement Obligation
The Company complies with the FASB guidance for ARO. This guidance affects the accounting for the decommissioning
of Palo Verde and the method used to report the decommissioning obligation. The Company also complies with the FASB guidance
for conditional ARO which primarily affects the accounting for the disposal obligations of the Company’s fuel oil storage tanks,
water wells, evaporative ponds and asbestos found at the Company’s gas-fired generating plants. The Company’s ARO are subject
to various assumptions and determinations such as: (i) whether a legal obligation exists to remove assets; (ii) estimation of the
fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation
rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time
with regard to these assumptions and determinations will change amounts recorded in the future as an expense for ARO. The
Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company
incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record
such retirement costs as incurred.
The ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2013 Palo Verde
decommissioning study. See Part II, Item 8, Financial Statements and Supplementary Data, Note E. The ARO liability is calculated
by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The
resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate.
As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost
estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume responsibility
for the permanent disposal of spent fuel, spent fuel costs have not been included in the ARO calculation. The Company maintains
six external trust funds with an independent trustee that are legally restricted to settling its ARO at Palo Verde. The fair value of
the funds at December 31, 2016 is $255.7 million.
The FASB guidance requires the Company to revise its previously recorded ARO for any changes in estimated cash flows
including changes in estimated probabilities related to timing of settlements. Any changes that result in an upward revision to
estimated cash flows shall be treated as a new liability. Any downward revisions to the estimated cash flows result in a reduction
to the previously recorded ARO. In December 2013, the Company implemented the 2013 Palo Verde decommissioning study, and
as a result, revised its ARO related to Palo Verde to decrease its estimated cash flows from the 2010 Study to the 2013 Study (see
Part II, Item 8, Financial Statements and Supplementary Data, Note E). The assumptions used to calculate the Palo Verde ARO
liability are as follows:
Original ARO liability
Incremental ARO liability
Credit-Risk
Adjusted
Discount Rate
9.50%
6.20%
Escalation
Rate
3.60%
3.60%
72
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
An analysis of the activity of the Company’s total ARO liability from January 1, 2014 through December 31, 2016, including
the effects of each year’s estimate revisions, is presented below. In 2016, the settled liabilities reflect the sale of the Company's
interest in Four Corners including the related ARO. In 2014, the estimate revision includes an adjustment to Four Corners due to
the early recognition of the obligation resulting from the Purchase and Sale Agreement with APS.
ARO liability at beginning of year
Liabilities incurred
Liabilities settled
Revisions to estimate
Accretion expense
ARO liability at end of year
2016
81,621
—
(6,993)
—
7,172
81,800
$
$
2015
74,577
189
—
—
6,855
81,621
$
$
2014
65,214
—
—
3,561
5,802
74,577
$
$
The Company has transmission and distribution lines which are operated under various property easement agreements. If
the easements were to be released, the Company may have a legal obligation to remove the lines; however, the Company has
assessed the likelihood of this occurring as remote. The majority of these easements include renewal options which the Company
routinely exercises. The amount of cost of removal collected in rates for non-legal liabilities has not been material.
G.
Common Stock
Overview
The Company’s common stock has a stated value of $1 per share, with no cumulative voting rights or preemptive rights.
Holders of the common stock have the right to elect the Company’s directors and to vote on other matters.
Long-Term Incentive Plan
On May 29, 2014, the Company’s shareholders approved an amended and restated stock-based long-term incentive plan (the
"Amended and Restated 2007 LTIP") and authorized the issuance of up to 1.7 million shares of the Company's common stock for
the benefit of directors and employees. Under the Amended and Restated 2007 LTIP, shares of the Company's common stock may
be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted
stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares,
purchase shares on the open market, or issue shares from shares of the Company's common stock the Company has repurchased
to meet the share requirements of the Amended and Restated 2007 LTIP. Beginning in 2015, shares of the Company's common
stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury
stock. As discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note A, the Company accounts for its stock-
based long-term incentive plan under the FASB guidance for stock-based compensation.
Restricted Stock with Service Condition and Other Stock-Based Awards. The Company has awarded restricted stock and
other stock-based awards under its long-term incentive plan. Restrictions from resale on restricted stock awards generally lapse
and awards vest over periods of one to three years. The market value of the unvested restricted stock at the date of grant is amortized
to expense over the restriction period net of anticipated forfeitures.
Other stock-based awards are fully vested and are expensed at fair value on the date of grant. Previously directors could
elect to receive retainers and meeting fees in cash, restricted stock, or a combination of cash and stock. On May 29, 2014, the
Board of Directors voted to revise the terms of the restricted stock awards granted to directors in lieu of cash for retainers and
meeting fees. Stock elections by directors in lieu of cash for retainer and meeting fees are now fully vested and are expensed at
fair value on the date of grant. The modification to 13,863 outstanding restricted stock awards granted to directors resulted in
forfeiture of those awards and the granting of new awards which were fully vested and expensed at $37.81 per share, the fair value
on the date of grant. Effective fiscal year ended December 31, 2015, other stock-based awards are not included in the tables below.
73
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The expense, deferred tax benefit, and current tax expense recognized related to restricted stock and other stock-based awards
in 2016, 2015 and 2014 is presented below (in thousands):
Expense (a)
Deferred tax benefit
$
2,594
$
908
2,755
$
964
2016
2015
2014
Current tax benefit recognized
_____________________
(a) Any capitalized costs related to these expenses is less than $0.3 million for all years.
183
43
3,471
1,215
39
The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in
2016, 2015 and 2014 is presented below (in thousands):
2016
2015
2014
Aggregated intrinsic value
Fair value at grant date
$
$
2,515
1,993
$
3,451
3,327
3,441
3,330
The unvested restricted stock transactions for 2016 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, 2015
91,210
$
Stock awards
Vested
Forfeitures
Restricted shares outstanding at December 31, 2016
74,181
(55,503)
(495)
109,393
36.61
40.95
35.91
36.88
39.90
$
1,767
$
5,087
_______________________
(a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term
of the outstanding restricted stock of approximately one year.
The weighted average fair value per share at grant date for restricted stock and other stock-base awards granted during 2016,
2015 and 2014 were:
Weighted average fair value per share
$
40.95
$
37.17
$
36.95
2016
2015
2014
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.
74
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)
2014-2016
$
512
January 25, 2017
32%
11,314
$
January 27, 2016
February 20, 2015
February 18, 2014
0%
0%
0%
0
0
0
932
851
2013-2015
1,502
2012-2014
954
2011-2013
—
—
—
In 2017, 2018 and 2019, subject to meeting certain performance criteria, additional performance shares could be awarded.
In accordance with the FASB guidance related to stock-based compensation, the Company recognizes the related compensation
expense by ratably amortizing the grant date fair value of awards over the requisite service period and the compensation expense
is only adjusted for forfeitures. Excluding the 2014 award, the maximum number of shares that can be issued under the plan are
206,898 shares.
The fair value at the date of each separate grant of performance shares was based upon a Monte Carlo simulation. The Monte
Carlo simulation reflected the structure of the performance plan which calculates the share payout on performance of the Company
relative to a defined peer group over a three-year performance period based upon total return to shareholders. The fair value was
determined as the average payout of one million simulation paths discounted to the grant date using a risk-free interest rate based
upon the constant maturity treasury rate yield curve at the grant date. The expected volatility of total return to shareholders is
calculated in accordance with the plan’s term structure and includes the volatilities of all members of the defined peer group.
The outstanding performance share awards at the 100% performance level is summarized below:
Number
Outstanding
Weighted
Average
Grant Date
Fair Value
Unrecognized
Compensation
Expense (b)
Aggregate
Intrinsic Value
(In thousands)
(In thousands)
Performance shares outstanding at December 31, 2015
(a)
Performance share awards
Performance shares expired
130,136
$
60,835
(24,527)
32.72
38.11
34.69
Performance shares outstanding at December 31, 2016
(a)
_______________________
(a) On December 15, 2015, the Company issued a stock based retention grant to the Chief Executive Officer (CEO) of 27,624
shares in accordance with the Amended and Restated 2007 LTIP that is eligible for vesting based on the achievement of certain
performance conditions and a five year service period, as stated in the CEO's employment agreement. The performance condition
was met as of November 2016 as determined by the Compensation Committee, and has been included in the beginning and
ending balance in the table above.
166,444
7,740
2,189
34.40
$
$
(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.
75
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
A summary of information related to performance shares for 2016, 2015 and 2014 is presented below:
Weighted average per share grant date fair value per share of
performance shares awarded
Compensation expense (in thousands) (a) (b)
Deferred tax benefit related to compensation expense (in thousands) (b)
$
38.11
$
1,655
579
35.72
1,042
365
$
26.36
1,181
413
2016
2015
2014
_____________________
(a) Includes adjustments for estimated forfeitures.
(b) Includes CEO retention grant.
Repurchase Program
No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2016. Detail
regarding the Company's stock repurchase program are presented below:
Shares repurchased (b)
Cost, including commission (in thousands)
Since 1999
(a)
Authorized
Shares
25,406,184
$
423,647
Total remaining shares available for repurchase at December 31, 2016
393,816
______________________
(a) Represents repurchased shares and cost since inception of the stock repurchase program in 1999.
(b) Shares repurchased does not include 86,735 treasury shares related to employee compensation arrangements outside of the
Company's repurchase programs. Beginning in 2015, shares of the Company's common stock issued for employee benefit
and stock incentive plans have been issued from the shares repurchased and held in treasury stock. The Company awarded
188,005 shares out of treasury stock during 2016.
The Company may in the future make purchases of shares of its common stock pursuant to its authorized program in open
market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares will
be available for issuance under employee benefit and stock incentive plans, or may be retired.
Dividend Policy
On December 30, 2016, the Company paid $12.6 million in quarterly cash dividends to shareholders. The Company paid a
total of $49.6 million, $47.1 million and $44.6 million in cash dividends during the twelve months ended December 31, 2016,
2015 and 2014, respectively. On January 26, 2017, the Board of Directors declared a quarterly cash dividend of $0.31 per share
payable on March 31, 2017 to shareholders of record as of the close of business on March 17, 2017.
76
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Basic and Diluted Earnings Per Share
The FASB guidance requires the Company to include share-based compensation awards that qualify as participating securities
in both basic and diluted earnings per share to the extent they are dilutive. A share-based compensation award is considered a
participating security if it receives non-forfeitable dividends or may participate in undistributed earnings with common stock. The
Company awards unvested restricted stock which qualifies as a participating security. The basic and diluted earnings per share are
presented below:
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
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
Years Ended December 31,
2015
2014
2016
40,350,688
57,345
40,408,033
40,274,986
33,576
40,308,562
40,190,991
20,726
40,211,717
$
$
$
$
$
$
$
$
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
$
$
$
$
$
$
$
$
91,428
(301)
91,127
91,428
(301)
91,127
1.105
1.165
2.270
1.105
1.165
2.270
The amount of restricted stock awards and performance shares at 100% performance level excluded from the calculation of
the diluted number of common shares outstanding because their effect was antidilutive is presented below:
Restricted stock awards
Performance shares (a)
Year Ended December 31,
2015
56,375
2016
53,703
47,246
66,804
2014
60,455
96,208
_____________________
(a) Certain performance shares were excluded from the computation of diluted earnings per share as no payouts would have
been required based upon performance at the end of each corresponding period.
77
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
H.
Accumulated Other Comprehensive Income (Loss)
Changes in Accumulated Other Comprehensive Income (Loss) (net of tax) by component are presented below (in thousands):
Unrecognized
Pension and
Post-
retirement
Benefit Costs
Net Unrealized
Gains (Losses)
on Marketable
Securities
Net Losses on
Cash Flow
Hedges
Accumulated
Other
Comprehensive
Income (Loss)
Balance at December 31, 2013
$
(21,330) $
36,240
$
(12,298)
$
2,612
Other comprehensive income (loss) before
reclassifications
Amounts reclassified from accumulated other
comprehensive income (loss)
Balance at December 31, 2014
Other comprehensive income (loss) before
reclassifications
Amounts reclassified from accumulated other
comprehensive income (loss)
Balance at December 31, 2015
Other comprehensive income before
reclassifications
Amounts reclassified from accumulated other
comprehensive income (loss)
Balance at December 31, 2016
$
(12,628)
8,694
(926)
(34,884)
3,777
1,238
(29,869)
7,363
(5,977)
38,957
(2,255)
(8,937)
27,765
6,904
—
224
(12,074)
—
264
(11,810)
(3,934)
(6,679)
(8,001)
1,522
(7,435)
(13,914)
—
14,267
(1,422)
(23,928) $
(6,206)
28,463
$
159
(11,651)
$
(7,469)
(7,116)
78
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Amounts reclassified from Accumulated Other Comprehensive Income (Loss) for the twelve months ended December 31,
2016, 2015 and 2014 are as follows (in thousands):
Details about Accumulated Other
Comprehensive Income (Loss)
Components
2016
2015
2014
Affected Line Item
in the Statements
of Operations
Amortization of pension and post-
retirement benefit costs:
Prior service benefit
Net loss
Income tax effect
Marketable securities:
$
7,407
$
(4,965)
2,442
(1,020)
1,422
$
6,574
(8,622)
(2,048)
810
(1,238)
7,659 (a)
(6,182) (a)
1,477 (a)
(551) Income tax expense
926 Net income
Net realized gain on sale of securities
7,640
11,114
Income tax effect
Loss on cash flow hedge:
Amortization of loss
Income tax effect
7,640
(1,434)
6,206
11,114
(2,177)
8,937
(498)
(498)
339
(159)
(467)
(467)
203
(264)
7,350
Investment and
interest income, net
Income before
income taxes
7,350
(1,373) Income tax expense
5,977 Net income
(438)
Interest on long-
term debt and
revolving credit
facility
Income before
income taxes
(438)
214 Income tax expense
(224) Net income
Total reclassifications
$
7,469
$
7,435
$
6,679
(a) These items are included in the computation of net periodic benefit cost. See Part II, Item 8, Financial Statements and
Supplementary Data, Note M for additional information.
79
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
I.
Long-Term Debt and Financing Obligations
Outstanding long-term debt and financing obligations are as follows:
Long-Term Debt:
Pollution Control Bonds (2):
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 (3):
6.00% Senior Notes, net of discount, due 2035 (7.12% effective interest rate)
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)
5.00% Senior Notes, net of discount, due 2044 (4.93% effective interest rate)
Total Senior Notes
RGRT Senior Notes (4):
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
Financing Obligations:
Revolving Credit Facility ($81,574 due in 2017) (5)
Total long-term debt and financing obligations
Current Portion (amount due within one year):
Current maturities of long term debt
Short-term borrowings under the revolving credit facility
December 31,
2016
2015 (1)
(In thousands)
$
62,619
58,471
36,492
33,193
190,775
393,861
147,331
148,939
302,955
993,086
62,582
58,441
36,465
33,011
190,499
393,693
147,282
148,783
147,717
837,475
49,950
44,845
94,795
1,278,656
49,883
44,803
94,686
1,122,660
81,574
1,360,230
141,738
1,264,398
(83,143)
(81,574)
$ 1,195,513
—
(141,738)
$ 1,122,660
_____________________
(1) The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related
to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt
liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and
interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify
$11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.
(2) Pollution Control Bonds ("PCBs")
The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 1.875%
2012 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds with an aggregate
principal amount of $33.3 million are subject to mandatory tender for purchase in September 2017 at which time the Company
will either repay or remarket these bonds.
(3) Senior Notes
The Senior Notes are unsecured obligations of the Company. They were issued pursuant to bond covenants that provide
limitations on the Company’s ability to enter into certain transactions. The 6.00% Senior Notes have an aggregate principal
amount of $400.0 million and were issued in May 2005. The proceeds, net of a $2.3 million discount, were used to fund the
retirement of the Company's first mortgage bonds. The Company amortizes the loss associated with a cash flow hedge
80
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
recorded in accumulated other comprehensive income to earnings as interest expense over the life of the 6.00% Senior Notes.
See Part II, Item 8, Financial Statements and Supplementary Data, Note O. This amortization is included in the effective
interest rate of the 6.00% Senior Notes.
The 7.50% Senior Notes have an aggregate principal amount of $150.0 million and were issued in June 2008. The proceeds,
net of a $1.3 million discount, were used to repay short-term borrowings of $44.0 million, fund capital expenditures and for
other general corporate purposes.
The 3.30% Senior Notes have an aggregate principal amount of $150.0 million were issued in December 2012. The proceeds,
net of a $0.3 million discount, were used to fund construction expenditures and for working capital and general corporate
purposes.
In December 2014, the Company issued 5.00% Senior Notes with an aggregate principal amount of $150.0 million. The
proceeds, net of a $0.5 million discount, were used to fund construction expenditures and for working capital and general
corporate purposes. In March 2016, the Company issued additional 5.00% Senior Notes with an aggregate principal amount
of $150.0 million. The proceeds from this issuance, after deducting the underwriters' commission, were $158.1 million. These
proceeds included accrued interest of $2.4 million and a $7.1 million premium before expenses. The net proceeds, from the
sale of these senior notes were used to repay outstanding short-term borrowings under the RCF. After the March 2016 issuance,
the Company's 5.00% Senior Notes due 2044 had a total principal amount outstanding of $300.0 million.
(4) RGRT Senior Notes
In 2010, the Company and RGRT, a Texas grantor trust through which the Company finances its portion of fuel for Palo Verde,
entered into a note purchase agreement with various institutional purchasers. Under the terms of the agreement, RGRT sold
to the purchasers $110 million aggregate principal amount of Senior Notes (the "Notes"). In August 2015, $15.0 million of
these Notes matured and were paid with borrowings from the RCF. In August 2017, $50.0 million of these Senior Notes will
mature. The Company will either repay or refinance this $50.0 million of Notes upon maturity. The Company guarantees the
payment of principal and interest on the Notes. In the Company’s financial statements, the assets and liabilities of RGRT are
reported as assets and liabilities of the Company.
RGRT pays interest on the Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the Notes,
in whole or in part, at any time at a redemption price equal to 100% of the principal amount to be redeemed together with the
interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on the prevailing market
interest rates. The agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The
Company was in compliance with these requirements throughout 2016.
The sale of the Notes was made by RGRT in reliance on a private placement exemption from registration under the Securities
Act of 1933, as amended. The proceeds of $109.4 million, net of issuance costs, from the sale of the Notes was used by RGRT
to repay amounts borrowed under the RCF and will enable future nuclear fuel financing requirements of RGRT to be met
with a combination of the Notes and amounts borrowed from the RCF.
(5) Revolving Credit Facility
On January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the
RCF with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication
agent, and various lending banks party thereto. As of December 31, 2016, the Company had available $300 million and the
ability to increase the RCF by up to $100 million with a term ending January 2019. On January 9, 2017, the Company exercised
its option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50
million to $350 million. The Company still has the option to extend the facility by one additional year to January 2021 and
to increase the RCF by up to $50 million (up to a total of $400 million) upon the satisfaction of certain conditions, more fully
set forth in the agreement, including obtaining commitments from lenders or third party financial institutions.
The RCF provides that amounts borrowed by the Company may be used for, among other things, working capital and general
corporate purposes. Any amounts borrowed by RGRT may be used, among other things, to finance the acquisition and
processing of nuclear fuel. Amounts borrowed by RGRT are guaranteed by the Company and the balance borrowed under
the RCF is recorded as short-term borrowings on the balance sheet. The RCF is unsecured. The RCF requires compliance
81
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements
throughout 2016. In August 2015, $15.0 million aggregate principal amount of Series A 3.67% Senior Notes of RGRT matured
and were paid utilizing borrowings under the RCF. As of December 31, 2016, the total amount borrowed by RGRT was $37.6
million for nuclear fuel under the RCF. As of December 31, 2016, $44.0 million of borrowings were outstanding under this
facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 2.0% as of
December 31, 2016.
As of December 31, 2016, the principal amount of scheduled maturities for the next five years of long-term debt are as follows
(in thousands):
2017
2018
2019
2020
2021
$
83,300
—
—
45,000
—
The $37.6 million of borrowings outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2017.
J.
Income Taxes
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at
December 31, 2016 and 2015 are presented below (in thousands):
Deferred tax assets:
Benefit of tax loss carryforwards
Alternative minimum tax credit carryforward
Pensions and benefits
Asset retirement obligation
Deferred fuel
Other
Total gross deferred tax assets
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
December 31,
2016
2015
$
60,749
16,620
57,756
26,929
—
(200)
161,854
35,153
16,620
61,673
28,042
1,488
15,421
158,397
(668,303)
(43,463)
(3,962)
(1,192)
(716,920)
(555,066) $
(608,738)
(41,100)
—
(3,796)
(653,634)
(495,237)
$
$
Based on the average annual book income before taxes for the prior three years, excluding the effects of unusual or infrequent
items, the Company believes that the deferred tax assets will be fully realized at current levels of book and taxable income.
82
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The Company recognized income tax expense for 2016, 2015 and 2014 as follows (in thousands):
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
Years Ended December 31,
2016
2015
2014
$
$
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
$
$
(1,250)
38,810
37,560
3,209
641
3,850
(322)
41,088
As of December 31, 2016, the Company had $16.6 million of AMT credit carryforwards that have an unlimited life. As of
December 31, 2016, the Company had $59.3 million of federal and $2.2 million of state tax loss carryforwards. If unused, both
the federal and state tax loss carryforwards have lives of 20 years and 5 years respectively. As of December 31, 2016, the Company
had $0.2 million of unrecognized tax benefits related to stock compensation which cannot be recognized until federal tax loss
carryforwards are fully utilized.
Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 35% to book
income before federal income tax as follows (in thousands):
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
Effective income tax rate
Years Ended December 31,
2016
52,740
$
2015
40,885
2014
46,381
$
$
2,633
(475)
(2,369)
1,389
53,918
$
52
(2,345)
(2,898)
(799)
34,895
$
1,902
(3,757)
(2,921)
(517)
41,088
35.8%
29.9%
31.0%
$
The Company files income tax returns in the United States federal jurisdiction and in the states of Texas, New Mexico and
Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal and New Mexico jurisdictions
for years prior to 2012. The Company is currently under audit in Texas for tax years 2007 through 2011. In June 2016, the Arizona
Department of Revenue discontinued their audits for tax years 2009 through 2012. The discontinuance of the audits did not have
a material impact on the Company's results of operations or financial position.
In the third quarter of 2016, the Company changed its accounting for state income taxes from the flow-through method to
the normalization method in accordance with the final orders from the PUCT and the NMPRC in its 2015 rate cases, effective
January 1, 2016. Under the flow-through method, the Company previously recorded deferred state income taxes and regulatory
liabilities and assets offsetting such deferred state income taxes at the expected cash flow to be reflected in future rates. Upon
implementation of normalization, the Company began amortizing the net regulatory asset for deferred state income taxes to deferred
income tax expense over a 15 year period as allowed by the regulators. In the third quarter of 2016, the Company began recording
deferred state income tax expense as required by normalization, retroactive to January 2016 as provided in the final orders. The
impact of the change was additional income tax expense of $5.1 million for the year ended December 31, 2016.
83
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
In November 2015, the FASB issued new guidance (ASU 2015-17, Balance Sheet Classification of Deferred Taxes) to
simplify the presentation of deferred income taxes. ASU 2015-17 requires that deferred tax liabilities and assets be classified as
noncurrent in a classified statement of financial position. ASU 2015-17 can be applied prospectively or retrospectively and is
effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those
annual periods and early adoption is permitted. The Company elected to implement ASU 2015-17 on a retrospective basis for
financial statements issued beginning March 31, 2016. The implementation of ASU 2015-17 did not have a material impact on
the Company's results of operations. The impact of ASU 2015-17 on the Company's Balance Sheet was to reclassify $21.6 million
of current deferred tax assets to long-term deferred tax liabilities at December 31, 2015.
The FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition
and measurement of a tax position taken or expected to be taken in a tax return. The Company recorded a decrease of $0.4 million
(net of an increase of $0.5 million), an unrecognized tax position of $0.8 million, and $2.1 million, in 2016, 2015, and 2014
respectively, related to transmission and distribution costs and other amounts deducted in current and prior year Texas franchise
tax returns. The Company recorded a decrease of $0.3 million in 2016 and a decrease of $1.3 million (net of an increase of $0.4
million) in 2014 related to tax credits taken and apportionment factors used in prior year Arizona income tax returns, which have
been settled through audit. A reconciliation of the December 31, 2016, 2015 and 2014 amounts of unrecognized tax benefits are
as follows (in thousands):
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
2016
2015
2014
$
$
6,000
400
—
100
(1,200)
5,300
$
$
5,200
500
—
300
—
6,000
$
$
7,200
300
—
2,200
(4,500)
5,200
If recognized, $2.6 million of the unrecognized tax position at December 31, 2016, would reduce the effective tax rate. The
Company recognized an income tax benefit for the decrease in unrecognized tax positions of $0.7 million for the year ended
December 31, 2016.
The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. For the
years ended December 31, 2016, 2015, and 2014 the Company recognized interest expense of $0.1 million, $0.2 million, and $0.1
million, respectively. The Company had approximately $0.8 million and $0.7 million accrued for the payment of interest and
penalties at December 31, 2016 and 2015, respectively.
84
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
K.
Commitments, Contingencies and Uncertainties
Power Purchase and Sale Contracts
To supplement its own generation and operating reserve requirements and to meet required renewable portfolio standards,
the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the
Company’s resource needs, the economics of the transactions and specific renewable portfolio requirements. The Company has
entered into the following significant agreements with various counterparties for the purchase and sale of electricity:
Type of Contract
Counterparty
Quantity
Term
Power Purchase and Sale Agreement
Power Purchase and Sale Agreement
Freeport
Freeport
25 MW
December 2008 through December
2018
100 MW
June 2006 through December 2021
Commercial
Operation
Date
N/A
N/A
Power Purchase Agreement
Power Purchase Agreement
Power Purchase Agreement
Power Purchase Agreement
Hatch Solar Energy Center
I, LLC
5 MW
July 2011 through June 2036
July 2011
NRG
20 MW
August 2011 through August 2031
August 2011
SunE EPE1, LLC
SunE EPE2, LLC
10 MW
12 MW
June 2012 through June 2037
May 2012 through May 2037
June 2012
May 2012
Power Purchase Agreement
Macho Springs Solar, LLC
50 MW
May 2014 through April 2034
May 2014
Power Purchase Agreement
Newman Solar LLC
10 MW
December 2014 through November
2044
December 2014
The Company has a firm Power Purchase and Sale Agreement with Freeport-McMoran Copper & Gold Energy Services
LLC ("Freeport") that provides for Freeport to deliver energy to the Company from the Luna Energy Facility (a natural gas-fired
combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy
at Greenlee, Arizona. The Company may purchase the quantities noted in the table above at a specified price at times when energy
is not exchanged under the Power Purchase and Sale Agreement. The agreement was approved by the FERC and will continue
through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power
Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold under the agreement.
The parties have agreed to increase the amount up to 125 MW through December 2018.
The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements. Namely,
the Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC to purchase all of the output from
a solar photovoltaic plant located in southern New Mexico which began commercial operation in July 2011. In June 2015, the
Company entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement
photovoltaic modules. The Company also entered into a 20-year contract with NRG Solar Roadrunner LLC ("NRG") to purchase
all of the output of a solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011.
In addition, the Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic
plants located in southern New Mexico, SunE EPE1, LLC and SunE EPE2, LLC which began commercial operation in June 2012
and May 2012, respectively.
Furthermore, the Company has a 20-year purchase power agreement with Macho Springs Solar, LLC to purchase the entire
generation output delivered from the 50 MW Macho Springs solar photovoltaic plant located in Luna County, New Mexico which
began commercial operation in May 2014. Finally, the Company has a 30-year purchase power agreement with Newman Solar
LLC to purchase the total output of approximately 10 MW from a solar photovoltaic plant on land subleased from the Company
in proximity to its Newman Power Station ("Newman"). This solar photovoltaic plant began commercial operation in
December 2014.
85
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Environmental Matters
General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and greenhouse
gas ("GHG") emissions, water discharges, soil and water quality, waste management and disposal, natural resources and other
environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and
requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative,
civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result
in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation,
or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to
comply.
Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the
EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The
allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the
controls necessary under the CAA to reduce sulfur dioxide ("SO2"), nitrogen oxides ("NOx"), and particulate matter ("PM"), and
that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by
law. On June 24, 2015, the parties filed with the U.S. District Court for New Mexico a settlement agreement ("CAA Settlement
Agreement") resolving this matter. On August 17, 2015, the U.S. District Court for New Mexico entered the CAA Settlement
Agreement. The agreement imposes a total civil penalty payable by the co-owners of Four Corners collectively in the amount of
$1.5 million, and it requires the co-owners to pay $6.7 million for environmental mitigation projects. At December 31, 2016, the
Company has accrued its remaining unpaid share of approximately $0.2 million related to this matter.
New Mexico Tax Matter Related to Coal Supplied to Four Corners
On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") issued a notice of assessment for coal
severance surtax, penalty, and interest totaling approximately $30.0 million related to coal supplied under the coal supply agreement
for Four Corners (the "Assessment"). The Company's share of the Assessment is approximately $1.5 million. On behalf of the
Four Corners participants, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with
respect to that partial payment in August 2013. The NMTRD denied the refund claim. On December 19, 2013, the coal supplier
and APS, on its own behalf and as operating agent for Four Corners, filed complaints with the New Mexico District Court contesting
both the validity of the Assessment and the refund claim denial. On June 30, 2015, the court ruled that the Assessment was not
valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously
paid under the applicable tax statute. The NMTRD filed a Notice of Appeal on August 31, 2015 with respect to the decision.
Thereafter, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment.
Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its
rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners participants agreed
to forgo refund rights with respect to all the contested amounts previously paid under the applicable tax statute, in addition to a
$1.0 million settlement payment. The Company paid its share of this settlement, approximately $47,000, in April 2016.
Lease Agreements
The Company leases land in El Paso, Texas, adjacent to Newman under a lease which expires in June 2033 with a renewal
option of 25 years. The Company also has several other leases for office, parking facilities and equipment which expire within the
next 4 years. The Company has transmission and distribution lines which are operated under various property easement agreements.
The majority of these easements include renewal options which the Company routinely exercises. These lease agreements do not
impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements.
The Company has no significant capital lease agreements.
86
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The Company's total annual rental expense related to operating leases was $1.7 million, $1.9 million, and $1.8 million for
2016, 2015 and 2014, respectively. As of December 31, 2016, the Company’s minimum future rental payments for the next five
years are as follows (in thousands):
2017
2018
2019
2020
2021
$
808
662
666
664
562
Union Matters
The Company has approximately 1,100 employees, about 38% of whom are covered by a collective bargaining agreement.
The International Brotherhood of Electrical Workers Local 960 ("Local 960") represents the Company’s employees working
primarily in the power plants, substations, line crews, meter reading and collection, facilities services, and customer service. The
Company entered into a new collective bargaining agreement effective September 3, 2016, with Local 960 for a three-year term
ending September 3, 2019. The agreement provides for pay increases of 3% on September 3, 2016, September 3, 2017 and on
September 3, 2018, respectively.
L.
Litigation
The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory
commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters,
the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly
analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual
disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the
matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect
on the financial position, results of operations or cash flows of the Company. The Company expenses legal costs, including expenses
related to loss contingencies, as they are incurred.
See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note K for discussion of the effects of
government legislation and regulation on the Company as well as certain pending legal proceedings.
87
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
M.
Employee Benefits
Retirement Plans
The Company’s Retirement Income Plan (the "Retirement Plan") is a qualified noncontributory defined benefit plan. Upon
retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement
Plan. Contributions from the Company are based on various factors such as the minimum funding amounts required by the Internal
Revenue Service ("IRS"), state and federal regulatory requirements, amounts collected from customers in the Company's Texas
and New Mexico jurisdictions and the annual cost of the Retirement Plan, as actuarially calculated. The assets of the Retirement
Plan are primarily invested in common collective trusts which hold equity securities, debt securities and cash equivalents and are
managed by a professional investment manager appointed by the Company.
The Company has two non-qualified retirement plans that are non-funded defined benefit plans. The Company's Supplemental
Retirement Plan covers certain former employees and directors of the Company. The Excess Benefit Plan, was adopted in 2004
and covers certain active and former employees of the Company. The benefit cost for the non-qualified retirement plans are based
on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.
During the quarter ended March 31, 2014, the Company implemented certain amendments to the Retirement Plan and Excess
Benefit Plan. In the first quarter of 2014, the Company offered a cash balance pension plan as an alternative to its current final
average pay pension plan for employees hired prior to January 1, 2014. The cash balance pension plan also included an enhanced
employer matching contribution to the employee’s respective 401(k) Defined Contribution Plan (discussed below). For employees
that elected the new cash balance feature of the plans, the pension benefit earned under the existing final average pay feature of
the plans was frozen as of March 31, 2014. Employees hired after January 1, 2014 were automatically enrolled in the cash balance
pension plan. The amendments to the plans were effective April 1, 2014. As a result of these actions, the Company remeasured
the assets and liabilities of the plans, based on actuarially determined estimates, using the close of the alternative choice election
period of February 28, 2014, as the remeasurement date.
Prior to December 31, 2013, employees who completed one year of service with the Company and worked at least a minimum
number of hours each year were covered by the final average pay formula of the plan. For participants that continue to be covered
by the final average pay formula, retirement benefits are based on the employee’s final average pay and years of service. The cash
balance pension plan covers employees beginning on their employment commencement date or re-employment commencement
date in any plan year in which the employee completes at least a minimum number of hours of service. Retirement benefits under
the cash balance pension plan are based on the employee’s cash balance account, consisting of pay credits and interest credits.
The Company complies with the FASB guidance on disclosure for pension and other post-retirement plans that requires
disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant
concentrations of risk.
88
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The obligations and funded status of the plans are presented below (in thousands):
December 31,
2016
2015
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Change in projected benefit obligation:
Benefit obligation at end of prior year
Service cost
Interest cost
Actuarial (gain) loss
Benefits paid
Benefit obligation at end of year
Change in plan assets:
$
Fair value of plan assets at end of prior year
Actual return (loss) on plan assets
Employer contribution
Benefits paid
Fair value of plan assets at end of year
Funded status at end of year
$
$
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) $
$
341,133
8,530
13,477
(19,290)
(18,144)
325,706
272,939
(3,760)
9,000
(18,144)
260,035
(65,671) $
28,397
262
1,018
(810)
(1,909)
26,958
—
—
1,909
(1,909)
—
(26,958)
Amounts recognized in the Company's balance sheets consist of the following (in thousands):
Current liabilities
Noncurrent liabilities
Total
December 31,
2016
2015
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
$
$
— $
(68,002)
(68,002) $
(2,696) $
(24,766)
(27,462) $
— $
(65,671)
(65,671) $
(2,102)
(24,856)
(26,958)
The accumulated benefit obligation in excess of plan assets is as follows (in thousands):
December 31,
2016
2015
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
$
Retirement
Income
Plan
(337,768) $
(314,071)
269,766
Non-Qualified
Retirement
Plans
(27,462) $
(25,550)
—
Retirement
Income
Plan
(325,706) $
(302,446)
260,035
Non-Qualified
Retirement
Plans
(26,958)
(25,785)
—
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,
2016
2015
Retirement
Income
Plan
121,052
(23,877)
97,175
$
$
Non-Qualified
Retirement
Plans
$
$
10,073
(185)
9,888
$
$
Retirement
Income
Plan
118,963
(27,344)
91,619
Non-Qualified
Retirement
Plans
$
$
9,592
(224)
9,368
89
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The following are the weighted-average actuarial assumptions used to determine the benefit obligations:
December 31,
2016
Non-Qualified
2015
Non-Qualified
Retirement
Income
Plan
Supplemental
Retirement
Plan
Excess
Benefit
Plan
Retirement
Income
Plan
Supplemental
Retirement
Plan
Excess
Benefit
Plan
Discount rate
Rate of compensation increase
4.29%
4.5%
3.76%
N/A
4.34%
4.5%
4.57%
4.5%
3.99%
N/A
4.59%
4.5%
The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each
measurement date. The discount rate used to measure the fiscal year end obligation is based on a segmented spot rate yield curve
that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit
payments. A 1% increase in the discount rate would decrease the December 31, 2016 retirement plans' projected benefit obligation
by 11.5%. A 1% decrease in the discount rate would increase the December 31, 2016 retirement plans' projected benefit obligation
by 14.1%.
The components of net periodic benefit cost are presented below (in thousands):
Years Ended December 31,
2016
2015
2014
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
$
$
7,705
12,161
(18,879)
6,554
(3,467)
296
878
—
785
(39)
$
$
8,530
13,477
(19,795)
$
262
1,018
—
$
8,284
14,001
(18,699)
9,710
(3,467)
937
(39)
8,178
(2,889)
303
1,041
—
675
(17)
$
4,074
$
1,920
$
8,455
$
2,178
$
8,875
$
2,002
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 in the service cost and interest
cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future periods.
Historically, the 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 change in estimate decreased the service and interest components of net periodic benefit cost in 2016 by
approximately $2.9 million.
90
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):
2016
2015
2014
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
$
$
8,644
—
$
1,266
—
$
4,266
—
(811) $
—
$
47,324
(33,700)
(6,554)
3,467
(785)
39
(9,710)
3,467
(937)
39
(8,178)
2,889
3,508
(500)
(675)
17
$
5,557
$
520
$
(1,977) $
(1,709) $
8,335
$
2,350
Net (gain) loss
Prior service benefit
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,
2016
2015
2014
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Retirement
Income
Plan
Non-Qualified
Retirement
Plans
Total recognized in net
periodic benefit cost and other
comprehensive income
$
9,631
$
2,440
$
6,478
$
469
$
17,210
$
4,352
The following are amounts in accumulated other comprehensive income that are expected to be recognized as
components of net periodic benefit cost during 2017 (in thousands):
Net loss
Prior service benefit
Retirement Income
Plan
$
7,530
(3,470)
Non-Qualified
Retirement Plans
825
$
(40)
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the
twelve months ended December 31:
2016
Non-Qualified
2015
Non-Qualified
2014 (a)
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
4.57%
4.83%
3.86%
3.99% 4.63%
N/A 4.87%
3.04% 3.9%
4.0%
4.0%
4.0%
3.4%
N/A
3.4%
4.1%
4.1%
4.1%
4.9%
4.9%
4.9%
3.9%
N/A
3.9%
4.9%
4.9%
4.9%
7.0%
N/A
N/A
7.5%
N/A
N/A
7.5%
N/A
N/A
4.5%
N/A
4.5%
4.5%
N/A
4.5%
4.75%
N/A
4.75%
_____________________
(a) The Retirement Plan and the Excess Benefit Plan were remeasured on February 28, 2014 due to the above mentioned plan
amendment. The discount rate used to remeasure the benefit obligation was 4.6% for the Retirement Plan and 4.5% for the
Excess Benefit Plan, compared to 4.9% for both plans as of January 1, 2014. All other assumptions remained consistent
with assumptions used at January 1, 2014.
91
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The Company’s overall expected long-term rate of return on assets is 7.0% effective January 1, 2016 and January 1, 2017,
which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. The expected long-term rate of
return is based on the weighted average of the expected returns on investments based upon the target asset allocation of the pension
fund. The Company’s target allocations for the plan’s assets are presented below:
Equity securities
Fixed income
Alternative investments
Total
December 31, 2016
50%
40%
10%
100%
The Retirement Plan invests the majority of its plan assets in common collective trusts which includes a diversified portfolio
of domestic and international equity securities and fixed income securities. Alternative investments of the Retirement Plan are
comprised of a real estate limited partnership and equity securities of real estate companies. The expected rate of returns for the
funds are assessed annually and are based on long-term relationships among major asset classes and the level of incremental returns
that can be earned by the successful implementation of different active investment management strategies. Equity and real estate
equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash, an
expected equity risk premium, as well as other economic factors. Fixed income returns are based on maturity, long-term inflation,
real rate of return and credit spreads. These assumptions also capture the expected correlation of returns between these asset classes
over the long term.
The FASB guidance on disclosure for pension plans requires disclosure of fair value measurements of plan assets. To increase
consistency and comparability in fair value measurements, the FASB guidance on fair value measurements established a fair value
hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•
Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices
of securities held in the mutual funds and underlying portfolios of the Retirement Plan are primarily obtained from
independent pricing services. These prices are based on observable market data. The Common Collective Trusts are
valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although
the underlying investments are traded on active markets. During the third quarter of 2016, the Company concluded that
the NAV used for determining the fair value of the investments in the Common Collective Trusts have readily determinable
fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy.
Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either
directly or indirectly. The fair value of these investments are based on evaluated prices that reflect observable market
information, such as actual trade information of similar securities, adjusted for observable differences.
•
Level 3 – Unobservable inputs using data that is not corroborated by market data.
92
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The fair value of the Company’s Retirement Plan assets at December 31, 2016 and 2015, and the level within the three levels
of the fair value hierarchy defined by the FASB guidance on fair value measurements are presented in the table below (in thousands):
Total Common Collective Trusts
Limited Partnership Interest in Real Estate (b)(c)
Total Plan Investments
$
Description of Securities
Cash and Cash Equivalents
Common Collective Trusts (a)
Equity funds
Fixed income funds
Real Estate Funds
Description of Securities
Cash and Cash Equivalents
Common Collective Trusts (a)
Equity funds
Fixed income funds
Real Estate Funds
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
$
— $
144,081
109,356
8,406
261,843
6,991
269,766
144,081
109,356
8,406
261,843
—
—
—
—
$
262,775
$
— $
Fair Value as of
December 31,
2015
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
$
1,266
$
1,266
$
— $
144,279
103,877
2,025
250,181
8,588
260,035
144,279
103,877
2,025
250,181
—
—
—
—
$
251,447
$
— $
—
—
—
—
—
—
—
—
—
—
—
—
Total Common Collective Trusts
Limited Partnership Interest in Real Estate (b)(c)
Total Plan Investments
$
_____________________
(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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15,
2015, and interim periods within those fiscal years.
(c)
93
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The table below reflects the changes in the fair value of investments in the real estate limited partnership during the period
(in thousands):
Balances at December 31, 2014
Unrealized loss in fair value
Balances at December 31, 2015
Sale of land
Unrealized loss in fair value
Balances at December 31, 2016
Fair Value of
Investments in
Real Estate
$
$
8,748
(160)
8,588
(775)
(822)
6,991
There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable
inputs during the twelve month periods ending December 31, 2016 and 2015. There were no purchases, issuances, and settlements
related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2016
and 2015.
The Company adheres to the traditional capital market pricing theory which maintains that over the long term, the risk of
owning equities should be rewarded with a greater return than available from fixed income investments. The Company seeks to
minimize the risk of owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying
its investments to limit its risks during falling markets. The investment manager has full discretionary authority to direct the
investment of plan assets held in trust within the guidelines prescribed by the Company through the plan’s investment policy
statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in
accordance with the Employee Retirement Income Security Act of 1974 ("ERISA") and Department of Labor ("DOL") regulations.
The Company contributes at least the minimum funding amounts required by the IRS for the Retirement Plan, as actuarially
calculated. The Company expects to contribute at least $10.0 million to its retirement plans in 2017.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):
2017
2018
2019
2020
2021
2022-2026
Retirement Income
Plan
$
16,113
19,080
18,771
18,923
19,755
107,916
Non-Qualified
Retirement Plans
2,698
$
2,060
2,025
1,957
1,907
8,949
401(k) Defined Contribution Plans
The Company sponsors 401(k) defined contribution plans covering substantially all employees. Annual matching
contributions made to the savings plans for the years 2016, 2015 and 2014 were $4.1 million, $3.9 million, and $3.0 million,
respectively. Historically, the Company had provided a 50 percent matching contribution up to 6 percent of the employee’s
compensation subject to certain other limits and exclusions. Effective April 1, 2014, for employees who enrolled in the cash
balance pension plan (discussed above), the Company provided a 100 percent matching contribution up to 6 percent of the
employee's compensation subject to certain other limits and exclusions.
Other Post-retirement Benefits
The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance
benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they
retire while working for the Company. Contributions from the Company are based on various factors such as the Plan's funded
status, the IRS tax deductible limit, state and federal regulatory requirements, amounts collected from customers in the Company's
Texas and New Mexico jurisdictions and the annual cost of the Plan, as actuarially calculated. The assets of the plan are primarily
invested in institutional funds which hold equity securities, debt securities, and cash equivalents and are managed by a professional
investment manager appointed by the Company.
94
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets, and the
funded status of the plan (in thousands):
Change in benefit obligation:
Benefit obligation at end of prior year
Service cost
Interest cost
Actuarial loss (gain)
Amendment (a) (b)
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 (loss) 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,
2016
2015
$
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) $
100,700
3,454
4,035
(11,423)
(824)
(4,544)
1,245
92,643
41,358
(469)
500
(4,544)
1,245
38,090
(54,553)
$
$
_____________________
(a) During October 2016, the Company approved and communicated a plan amendment that resulted in a remeasurement of the
Company's Other Post-retirement Benefit Plan. Effective January 1, 2017, retirees and dependents that are less than 65 years
of age are offered a choice between a $1,000 and $2,250 deductible plan. Additionally, retirees and dependents that are 65
years of age or greater were covered by a fully insured Medicare advantage plan.
(b) Amendment relates to modification of the Company's Other Post-retirement Benefit Plan which increased mail order co-
payments for post age 65. The amendment was approved in 2015 and became effective January 1, 2016.
Amounts recognized in the Company's balance sheets consist of the following (in thousands):
Current liabilities
Noncurrent liabilities
Total
December 31,
2016
2015
$
$
— $
(34,400)
(34,400) $
—
(54,553)
(54,553)
Pre-tax amounts recognized in accumulated other comprehensive income consist of the following (in thousands):
Net gain
Prior service benefit
Total
December 31,
2016
(26,285) $
(41,009)
(67,294) $
2015
(38,802)
(12,213)
(51,015)
$
$
95
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The following are the weighted-average actuarial assumptions used to determine the accrued post-retirement benefit
obligations:
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,
2016
2015
4.36%
4.59%
6.50%
4.50%
7.50%
10.50%
4.50%
2026
7.00%
7.00%
7.00%
7.00%
4.50%
2026
_____________________
(a) Pre-65 medical reaches the ultimate trend rate in 2025. Additionally, the Post-65 medical trend is assumed to be
4.50% for all years into the future.
The discount rate is reviewed at each measurement date. The discount rate used to measure the fiscal year end obligation is
based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable
to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2016
accumulated post-retirement benefit obligation by 13.1%. A 1% decrease in the discount rate would increase the December 31,
2016 accumulated post-retirement benefit obligation by 16.7%.
Net periodic benefit cost is made up of the components listed below (in thousands):
Service cost
Interest cost
Expected return on plan assets
Amortization of:
Prior service benefit
Net gain
Net periodic benefit cost
Years Ended December 31,
2016
2015
2014
$
2,769
3,167
(1,835)
(3,901)
(2,374)
(2,174) $
3,454
4,035
(2,070)
(3,068)
(2,025)
326
$
$
2,845
4,463
(2,116)
(4,753)
(2,671)
(2,232)
$
$
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 in the service cost and
interest cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future
periods. Historically, the 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 change in estimate decreased the service and interest components of net periodic benefit cost in 2016
by approximately $0.8 million.
96
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):
Net (gain) loss
Prior service benefit
Amortization of:
Prior service benefit
Net gain
Total recognized in other comprehensive income
Years Ended December 31,
2016
2015
2014
$
$
$
10,143
(32,697)
(8,884) $
(824)
3,901
2,374
(16,279) $
3,068
2,025
(4,615) $
3,496
—
4,753
2,671
10,920
The total amount recognized in net periodic benefit cost and other comprehensive income are presented below (in thousands):
Total recognized in net periodic benefit cost and other comprehensive income
$
Years Ended December 31,
2016
(18,453) $
2015
2014
(4,289) $
8,688
The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic
benefit cost during 2017 is a prior service benefit of $6.2 million and a net gain of $1.6 million.
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve
months ended December 31:
Discount rate:
Benefit obligation
Service cost
Interest cost
Expected long-term return on plan assets
Health care cost trend rates:
Initial
Ultimate
Year ultimate reached
2016 (a)
2015
2014
January 1 -
September 30
4.59%
4.91%
3.86%
October 1 -
December 31
3.75%
4.03%
3.15%
4.875%
7.00%
4.5%
2026
4.1%
4.1%
4.1%
5.2%
7.25%
4.5%
2026
4.9%
4.9%
4.9%
5.2%
7.5%
4.5%
2026
_____________________
(a) The actuarial assumptions are evaluated by the Company at each measurement date. The Other Post-retirement Benefits Plan
was remeasured at October 1, 2016 due to a plan amendment.
For measurement purposes, a 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed
for 2016. The rate was assumed to decrease gradually to 4.5% for 2026 and remain at that level thereafter. Assumed health care
cost trend rates have a significant effect on the amounts reported for the health care plan. The effect of a 1% change in these
assumed health care cost trend rates would increase or decrease the December 31, 2016 benefit obligation by $11.2 million or
$9.0 million, respectively. In addition, a 1% change in said rate would increase or decrease the aggregate 2016 service and interest
cost components of the net periodic benefit cost by $1.3 million or $1.0 million, respectively.
97
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 4.875% effective January 1, 2016
and January 1, 2017. The expected long-term rate of return is based on the after-tax weighted average of the expected returns on
investments based upon the target asset allocation. The Company’s target allocations for the plan’s assets are presented below:
Equity securities
Fixed income
Alternative investments
Total
December 31, 2016
65%
30%
5%
100%
The Other Post-retirement Benefit Plan invests the majority of its plan assets in institutional funds which includes a diversified
portfolio of domestic and international equity securities and fixed income securities. The asset portfolio also includes cash
equivalents and a real estate limited partnership. The expected rates of return for the funds are assessed annually and are based
on long-term relationships among major asset classes and the level of incremental returns that can be earned by the successful
implementation of different active investment management strategies. Equity returns are based on estimates of long-term inflation
rate, real rate of return, 10-year Treasury bond premium over cash, an expected equity risk premium, as well as other economic
factors. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads. These assumptions
also capture the expected correlation of returns between these asset classes over the long term.
The FASB guidance on disclosure for other post-retirement benefit plans requires disclosure of fair value measurements of
plan assets. To increase consistency and comparability in fair value measurements, the FASB guidance on fair value measurements
established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as
follows:
•
•
•
Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices
of securities held in the mutual funds and underlying portfolios of the Other Post-retirement Benefits Plan are primarily
obtained from independent pricing services. These prices are based on observable market data. The institutional funds
are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market
although the underlying investments are traded on active markets. During the third quarter of 2016, the Company concluded
that the NAV used for determining the fair value of the investments in the institutional funds have readily determinable
fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy.
Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either
directly or indirectly. The fair value of these investments are based on evaluated prices that reflect observable market
information, such as actual trade information of similar securities, adjusted for observable differences.
Level 3 – Unobservable inputs using data that is not corroborated by market data.
98
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The fair value of the Company’s Other Post-retirement Benefits Plan assets at December 31, 2016 and 2015, and the level
within the three levels of the fair value hierarchy defined by the FASB guidance on fair value measurements are presented in the
table below (in thousands):
Description of Securities
Institutional Funds (a)
Equity funds
Fixed income funds
Total Institutional Funds
Limited Partnership Interest in Real Estate (b) (c)
Total Plan Investments
Description of Securities
Institutional Funds (a)
Equity funds
Fixed income funds
Total Institutional Funds
Limited Partnership Interest in Real Estate (b) (c)
Total Plan Investments
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)
$
$
26,133
11,671
37,804
1,311
39,115
$
$
26,133
11,671
37,804
— $
—
—
$
37,804
$
— $
—
—
—
—
Fair Value as of
December 31,
2015
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
$
$
24,881
11,599
36,480
1,610
38,090
$
$
24,881
11,599
36,480
— $
—
—
$
36,480
$
— $
—
—
—
—
___________________
(a) The institutional funds are invested in equity or fixed income securities, or a combination thereof. The investment objective
of each fund is to produce returns in excess of, or commensurate with, its predefined index.
(b) This investment is a commercial real estate partnership that purchases land, develops limited infrastructure, and sells it for
commercial development. The Company was restricted from selling its partnership interest during the life of the partnership,
which spanned 7 years. Return of investment is realized as land is sold. The fair value of the limited partnership interest in
real estate is based on the NAV of the partnership which reflects the appraised value of the land. The partnership term expired
on June 30, 2016. Upon expiration, dissolution of the partnership commenced and, as a result, the general partner of the
partnership is attempting to sell the remaining inventory as soon as possible at the highest pricing possible.
In the first quarter of 2016, the Company implemented ASU 2015-07, Fair Value Measurement (Topic 820) which eliminates
the requirement to categorize investments in the fair value hierarchy if the fair value is measured at NAV per share (or its
equivalent) using the practical expedient in the FASB’s fair value measurement guidance. The fair value amounts presented
in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of
financial position. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15,
2015, and interim periods within those fiscal years.
(c)
The table below reflects the changes in the fair value of the investments in real estate during the period (in thousands):
Balance at December 31, 2014
Unrealized loss in fair value
Balance at December 31, 2015
Sale of land
Unrealized loss in fair value
Balance at December 31, 2016
Fair Value of
Investments in
Real Estate
1,640
(30)
1,610
(145)
(154)
1,311
$
$
99
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable
inputs during the twelve month periods ending December 31, 2016 and 2015. There were no purchases, issuances, and settlements
related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2016
and 2015.
The Company adheres to the traditional capital market pricing theory which maintains that over the long term, the risk of
owning equities should be rewarded with a greater return than available from fixed income investments. The Company seeks to
minimize the risk of owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying
its investments to limit its risks during falling markets. The investment manager has full discretionary authority to direct the
investment of plan assets held in trust within the guidelines prescribed by the Company through the plan’s investment policy
statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in
accordance with the ERISA and DOL regulations.
The Company expects to contribute $1.5 million to its other post-retirement benefits plan in 2017. The following benefit
payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):
2017
2018
2019
2020
2021
2022-2026
$
2,622
2,880
3,057
3,320
3,510
20,084
Annual Short-Term Incentive Plan
The Annual Short-Term Incentive Plan (the "Incentive Plan") provides for the payment of cash awards to eligible Company
employees, including each of its named executive officers. Payment of awards is based on the achievement of performance measures
reviewed and approved by the Company’s Board of Directors’ Compensation Committee. Generally, these performance measures
are based on meeting certain financial, operational and individual performance criteria. The financial performance goals are based
on earnings per share and the operational performance goals are based on compliance, customer satisfaction, and reliability. If a
specified level of earnings per share is not attained, no amounts will be paid under the Incentive Plan, unless the Compensation
Committee determines otherwise. In 2016, the Company reached the required levels of earnings per share, customer satisfaction,
reliability, compliance, and safety goals for an incentive payment of $12.5 million. In 2015 and 2014, the Company reached the
required levels of earnings per share, safety, compliance, and customer satisfaction goals for an incentive payment of $10.5 million
and $7.4 million, respectively. The Company has renewed the Incentive Plan in 2017 with similar goals.
100
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
N.
Franchises and Significant Customers
Franchises
The Company operates under franchise agreements with several cities in its service territory, including one with El Paso,
Texas, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve
its customers within El Paso. Pursuant to the El Paso franchise agreement, which was amended in 2010, the Company pays to the
City of El Paso, on a quarterly basis, a fee equal to 4.00% of gross revenues the Company receives for the generation, transmission
and distribution of electrical energy and other services within the city. The 2005 El Paso franchise agreement set the franchise fee
at 3.25% of gross revenues, but the 2010 amendment added an incremental fee equal to 0.75% of gross revenues to be placed in
a restricted fund to be used by the city solely for economic development and renewable energy purposes. Any assignment of the
franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of
the City of El Paso. The El Paso franchise agreement is set to expire on July 31, 2030.
The Company does not have a written franchise agreement with the City of Las Cruces, the second largest city in its service
territory. The Company provides electric distribution service to the City of 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 2.8% of the Company's annual retail revenues. In July 2014, the Company signed an agreement with
Fort Bliss under which Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company
serves White Sands under the applicable New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under
which the Company provides retail electric service and limited wheeling services to HAFB under the applicable New Mexico
tariffs. As stated in the contract, HAFB will purchase the full output of a Company-owned 5 MW solar facility upon its completed
construction, with HAFB's other power requirements provided under the applicable New Mexico tariffs.
101
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
O.
Financial Instruments and Investments
The FASB guidance requires the Company to disclose estimated fair values for its financial instruments. The Company has
determined that cash and temporary investments, investment in debt securities, accounts receivable, decommissioning trust funds,
long-term debt, short-term borrowings under the RCF, accounts payable and customer deposits meet the definition of financial
instruments. The carrying amounts of cash and temporary investments, accounts receivable, accounts payable and customer
deposits approximate fair value because of the short maturity of these items. Investments in debt securities and decommissioning
trust funds are carried at fair value.
Long-Term Debt and Short-Term Borrowings Under the RCF. The fair values of the Company's long-term debt and short-
term borrowings under the RCF are based on estimated market prices for similar issues and are presented below (in thousands):
Pollution Control Bonds
Senior Notes
RGRT Senior Notes (2)
RCF (2)
Total
December 31,
2016
2015
Carrying
Amount (1)
Estimated
Fair Value
Carrying
Amount (1)
Estimated
Fair Value
$
190,775
993,086
94,795
81,574
$ 1,360,230
$
206,818
1,112,285
98,855
81,574
$ 1,499,532
$
190,499
837,475
94,686
141,738
$ 1,264,398
$
212,624
829,864
100,345
141,738
$ 1,284,571
__________________
(1) The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related
to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt
liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and
interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify
$11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.
(2) Nuclear fuel financing, as of December 31, 2016 and December 31, 2015, is funded through the $95 million RGRT Senior
Notes and $37.6 million and $33.7 million, respectively under the RCF. As of December 31, 2016, $44.0 million was
outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2015, $108.0 million
amount was outstanding under the RCF for working capital or general corporate purposes. The interest rate on the Company’s
borrowings under the RCF is reset throughout the period reflecting current market rates. Consequently, the carrying value
approximates fair value.
Treasury Rate Locks. The Company entered into treasury rate lock agreements in 2005 to hedge against potential movements
in the treasury reference interest rate pending the issuance of the 6% Senior Notes. The treasury rate lock agreements met the
criteria for hedge accounting and were designated as a cash flow hedge. In accordance with cash flow hedge accounting, the
Company recorded the loss associated with the fair value of the cash flow hedge, net of tax, as a component of accumulated other
comprehensive loss and amortizes the accumulated comprehensive loss to earnings as interest expense over the life of the 6%
Senior Notes. In 2017, approximately $0.5 million of this accumulated other comprehensive loss item will be reclassified to
interest expense.
Contracts and Derivative Accounting. The Company uses commodity contracts to manage its exposure to price and
availability risks for fuel purchases and power sales and purchases and these contracts generally have the characteristics of
derivatives. The Company does not trade or use these instruments with the objective of earning financial gains on the commodity
price fluctuations. The Company has determined that all such contracts outstanding at December 31, 2016, except for certain
natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the "normal purchases
and normal sales" exception provided in the FASB guidance for accounting for derivative instruments and hedging activities, and,
as such, were not required to be accounted for as derivatives.
102
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets,
are reported at fair value which was $255.7 million and $239.0 million at December 31, 2016 and 2015, respectively. These
securities are classified as available for sale and recorded at their estimated fair value using the FASB guidance for certain
investments in debt and equity securities. The reported fair values include gross unrealized losses on marketable securities whose
impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of
these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized
loss position (in thousands):
December 31, 2016
Less than 12 Months
12 Months or Longer
Total
Fair
Value
Unrealized
Losses
Fair
Value
Unrealized
Losses
Fair
Value
Unrealized
Losses
Description of Securities (1):
Federal Agency Mortgage Backed Securities
U.S. Government Bonds
Municipal Obligations
Corporate Obligations
Total Debt Securities
Common Stock
Institutional Funds-International Equity
$
$ 11,582
31,655
9,596
7,971
60,804
2,760
22,945
Total Temporarily Impaired Securities
$ 86,509
$
____________________
(1)
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)
December 31, 2015
Less than 12 Months
12 Months or Longer
Total
Fair
Value
Unrealized
Losses
Fair
Value
Unrealized
Losses
Fair
Value
Unrealized
Losses
$
9,383
24,094
8,286
6,058
47,821
3,584
22,454
$ 73,859
$
$
(97) $
(310)
(160)
(722)
(1,289)
(344)
(768)
1,113
14,272
7,388
2,307
25,080
—
—
(2,401) $ 25,080
$
$
(47) $ 10,496
(623)
38,366
(446)
15,674
(228)
8,365
(1,344)
72,901
3,584
—
22,454
—
(1,344) $ 98,939
$
$
(144)
(933)
(606)
(950)
(2,633)
(344)
(768)
(3,745)
Description of Securities (2):
Federal Agency Mortgage Backed Securities
U.S. Government Bonds
Municipal Obligations
Corporate Obligations
Total Debt Securities
Common Stock
Institutional Funds-International Equity
Total Temporarily Impaired Securities
______________________
(2)
Includes approximately 133 securities.
The Company monitors the length of time specific securities trade below its cost basis along with the amount and percentage
of the unrealized loss in determining if a decline in fair value of marketable securities below recorded cost is considered to be
other than temporary. The Company recognizes impairment losses on certain of its securities deemed to be other than temporary.
In accordance with the FASB guidance, these impairment losses are recognized in net income, and a lower cost basis is established
for these securities. In addition, the Company will research the future prospects of individual securities as necessary. The Company
does not anticipate expending monies held in trust before 2044 or a later period when decommissioning of Palo Verde begins.
For the twelve months ended December 31, 2016, 2015, and 2014, the Company recognized other than temporary impairment
losses on its available-for-sale securities as follows (in thousands):
Unrealized holding losses included in pre-tax income
2016
2015
2014
$
(352) $
(338) $
—
103
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The reported securities also include gross unrealized gains on marketable securities which have not been recognized in the
Company’s net income. The table below presents the unrecognized gross unrealized gains and the fair value of these securities,
aggregated by investment category (in thousands):
Description of Securities:
Federal Agency Mortgage Backed Securities
U.S. Government Bonds
Municipal Obligations
Corporate Obligations
Total Debt Securities
Common Stock
Equity Mutual Funds
Cash and Cash Equivalents
Total
December 31, 2016
December 31, 2015
Fair
Value
Unrealized
Gains
Fair
Value
Unrealized
Gains
$
$
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
$
$
9,589
12,033
8,671
10,110
40,403
72,636
18,853
8,204
140,096
$
$
438
136
332
368
1,274
37,001
91
—
38,366
The Company’s marketable securities include investments in mortgage backed securities, municipal, corporate and federal
debt obligations. The contractual year for maturity for these available-for-sale securities as of December 31, 2016 is as follows
(in thousands):
Total
2017
2018 through
2021
2022 through
2026
2027 and
Beyond
Municipal Debt Obligations
Corporate Debt Obligations
U.S. Government Bonds
Federal Agency Mortgage Backed Securities
$
$
16,144
22,413
61,868
19,448
$
990
—
14,272
—
$
6,253
8,664
22,495
5
$
8,139
6,090
14,786
390
762
7,659
10,315
19,053
The Company’s marketable securities in its decommissioning trust funds are sold from time to time and the Company uses
the specific identification basis to determine the amount to reclassify out of accumulated other comprehensive income and into
net income. The proceeds from the sale of these securities during the twelve months ended December 31, 2016, 2015, and 2014
and the related effects on pre-tax income are as follows (in thousands):
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) losses reclassified out of accumulated other comprehensive income
Net gains (losses) in other comprehensive income
2016
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) $
2014
108,311
7,858
(508)
—
7,350
10,827
(7,350)
3,477
$
$
$
$
$
Fair Value Measurements. The FASB guidance requires the Company to provide expanded quantitative disclosures for
financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company's
decommissioning trust investments and investments in debt securities which are included in deferred charges and other assets on
the Balance Sheets. The Company has no liabilities that are measured at fair value on a recurring basis. The FASB guidance
104
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as
follows:
•
•
•
Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial
assets utilizing Level 1 inputs include the nuclear decommissioning trust investments in active exchange-traded equity
securities, mutual funds and U.S. Treasury securities that are in a highly liquid and active market. The Institutional Funds
are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market
although the underlying investments are traded on active markets. During the third quarter of 2016, the Company concluded
that the NAV used for determining the fair value of the Institutional Funds- International Equity investments have readily
determinable fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy.
Level 2 - Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either
directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in
fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable
market information, such as actual trade information of similar securities, adjusted for observable differences.
Level 3 - Unobservable inputs using data that is not corroborated by market data and primarily based on internal Company
analysis using models and various other analysis. Financial assets utilizing Level 3 inputs are the Company's investment
in debt securities.
The securities in the Company's decommissioning trust funds are valued using prices and other relevant information generated
by market transactions involving identical or comparable securities. The FASB guidance identifies this valuation technique as the
"market approach" with observable inputs. The Company analyzes available-for-sale securities to determine if losses are other
than temporary.
The fair value of the Company’s decommissioning trust funds and investments in debt securities at December 31, 2016
and 2015, and the level within the three levels of the fair value hierarchy defined by the FASB guidance are presented in the
table below (in thousands):
Description of Securities
Trading Securities:
Investments in Debt Securities
Available for sale:
U.S. Government Bonds
Federal Agency Mortgage Backed Securities
Municipal Obligations
Corporate Obligations
Subtotal, Debt Securities
Common Stock
Equity Mutual Funds
Institutional Funds-International Equity
Cash and Cash Equivalents
Total available for sale
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)
$
$
$
1,421
61,868
19,448
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
$
$
—
—
—
—
—
—
—
—
—
—
105
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Description of Securities
Trading Securities:
Investments in Debt Securities
Available for sale:
U.S. Government Bonds
Federal Agency Mortgage Backed Securities
Municipal Obligations
Corporate Obligations
Subtotal, Debt Securities
Common Stock
Equity Mutual Funds
Institutional Funds-International Equity
Cash and Cash Equivalents
Total available for sale
Fair Value as
of
December 31,
2015
Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
$
$
$
1,543
50,399
20,085
24,345
18,475
113,304
76,220
18,853
22,454
8,204
239,035
$
$
$
— $
— $
1,543
50,399
—
—
—
50,399
76,220
18,853
22,454
8,204
176,130
$
— $
20,085
24,345
18,475
62,905
—
—
—
—
62,905
$
$
—
—
—
—
—
—
—
—
—
—
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.
$
2016
2015
1,543
(122)
1,421
$
$
1,653
(110)
1,543
There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable
inputs during the twelve month periods ending December 31, 2016 and 2015. There were no purchases, sales, issuances, and
settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending
December 31, 2016 and 2015.
106
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
P.
Supplemental Statements of Cash Flows Disclosures
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit
facility
Income taxes, net of refund
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
Years Ended December 31,
2016
2015
2014
(In thousands)
$
69,990
$
62,297
$
2,328
1,000
27,720
4,789
1,236
—
(6,660)
1,567
54,792
6,876
—
7,314
3,025
(a) The Company sold its interest in Four Corners for approximately $32.0 million based on the book value as defined in
the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million to reflect
APS's affiliate assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation
expense, respectively. The sales price was also adjusted downward by approximately $1.3 million for closing adjustments
and other assets and liabilities assumed by APS's affiliate. At the closing of the sale, the Company received approximately
$4.2 million in cash, subject to post-closing adjustments.
107
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Q.
Selected Quarterly Financial Data (Unaudited)
The following table summarizes the Company’s unaudited results of operations on a quarterly basis. The quarterly earnings
per share amounts for a year will not add to the earnings per share for that year due to the weighting of shares used in calculating
per share data.
Operating revenues (1)
Operating income (loss)
Net income (loss)
Basic earnings per share:
Net income (loss)
Diluted earnings per share:
Net income (loss)
Dividends declared per share of
common stock
2016 Quarters
2015 Quarters
4th
3rd (2)
2nd
1st
4th
3rd
2nd
1st
(In thousands except for share data)
$188,037
$323,225
$217,865
20,470
129,857
5,656
74,636
44,697
22,284
$157,809
(163)
(5,808)
$176,902
$289,713
$219,508
$163,746
8,312
648
88,047
56,740
41,872
21,072
7,960
3,458
0.14
1.84
0.55
(0.14)
0.02
1.40
0.52
0.09
0.14
1.84
0.55
(0.14)
0.02
1.40
0.52
0.09
0.310
0.310
0.310
0.295
0.295
0.295
0.295
0.280
________________
(1) Operating revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months.
Comparisons among quarters of a year may not represent overall trends and changes in operations.
(2) For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail
Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016
the cumulative effect of the PUCT Final Order which related back to January 12, 2016. See Part II, Item 8, Financial
Statements and Supplementary Data, Note C.
108
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management,
including our chief executive officer and our chief financial officer, we conducted an evaluation pursuant to Rule 13a-15(b)
under the Exchange Act of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Exchange Act. Based
on that evaluation, our chief executive officer and our chief financial officer concluded that, as of December 31, 2016, our
disclosure controls and procedures are effective.
Management’s Annual Report on Internal Control Over Financial Reporting. Management’s Annual Report on Internal
Control over Financial Reporting is included herein under the caption "Management Report on Internal Control Over Financial
Reporting" on page 49 of this Annual Report on Form 10-K.
Changes in internal control over financial reporting. There were no changes in our internal control over financial
reporting in connection with the evaluation required by paragraph (d) of the Exchange Act Rules 13a-15 or 15d-15, that
occurred during the quarter ended December 31, 2016, that materially affected, or that were reasonably likely to materially
affect, our internal control over financial reporting.
Item 9B. Other Information
None.
The information set forth in Part III and Part IV has been omitted from this Annual Report to Shareholders.
PART III and PART IV
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EVOLUTION
POWER
INNOVATION