10-K 1 a201510-k.htm FORM 10-K 10-K
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 

_______________________
Form 10-K
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission file number 001-14206
El Paso Electric Company
(Exact name of registrant as specified in its charter)
Texas
 
74-0607870
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
Stanton Tower, 100 North Stanton, El Paso, Texas
 
79901
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code: (915) 543-5711
Securities Registered Pursuant to Section 12(b) of the Act: 
Title of each class
 
Name of each exchange on which registered
Common Stock, No Par Value
 
New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
YES  x    NO ¨ 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
YES  ¨     NO  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   YES  x   NO ¨ 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES  x    NO  ¨ 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 126-2 of the Exchange Act.
Large accelerated filer
 
x
Accelerated filer
 
o
 
 
 
 
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
Smaller reporting company
 
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    YES  ¨    NO  x
As of June 30, 2015, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,380,612,681 (based on the closing price as quoted on the New York Stock Exchange on that date).
As of January 31, 2016, there were 40,483,000 shares of the Company’s no par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for the 2016 annual meeting of its shareholders are incorporated by reference into Part III of this report.

 
 
 


DEFINITIONS
The following abbreviations, acronyms or defined terms used in this report are defined below:
 
Abbreviations, Acronyms or Defined Terms
  
Terms
 
 
 
ANPP Participation Agreement
  
Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended
APS
  
Arizona Public Service Company
ASU
  
Accounting Standards Update
Company
  
El Paso Electric Company
DOE
  
United States Department of Energy
El Paso
  
City of El Paso, Texas
FASB
  
Financial Accounting Standards Board
FERC
  
Federal Energy Regulatory Commission
Fort Bliss
  
Fort Bliss, the United States Army post next to El Paso, Texas
Four Corners
  
Four Corners Generating Station
HAFB
 
Holloman Air Force Base
IRS
 
Internal Revenue Service
kV
  
Kilovolt(s)
kW
  
Kilowatt(s)
kWh
  
Kilowatt-hour(s)
Las Cruces
  
City of Las Cruces, New Mexico
MW
  
Megawatt(s)
MWh
  
Megawatt-hour(s)
NMPRC
  
New Mexico Public Regulation Commission
Net dependable generating capability
  
The maximum load net of plant operating requirements that a generating plant can supply under specified conditions for a given time interval, without exceeding approved limits of temperature and stress
NRC
  
Nuclear Regulatory Commission
Palo Verde
  
Palo Verde Nuclear Generating Station
Palo Verde Participants
  
Those utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement
PNM
  
Public Service Company of New Mexico
PUCT
  
Public Utility Commission of Texas
RGEC
  
Rio Grande Electric Cooperative
RGRT
  
Rio Grande Resources Trust
TEP
  
Tucson Electric Power Company
White Sands
 
White Sands Missile Range
 


               
 
( i)
 


TABLE OF CONTENTS
 
 
 
 
Item
Description
Page
 
 
1

1A

1B

2

3

4

 
 
 
 
 
 
 
 
5

6

7

7A

8

9

9A

9B

 
 
 
 
 
10

11

12

13

14

 
 
 
 
 
15

 


               
 
( ii)
 


FORWARD-LOOKING STATEMENTS
Certain matters discussed in this Annual Report on Form 10-K other than statements of historical fact are "forward-looking statements," within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Forward-looking statements often include words like we "believe", "anticipate", "target", "project", "expect", "predict", "pro forma", "estimate", "intend", "will", "is designed to", "plan" and words of similar meaning, or by the Company's discussion of strategies or trends. Forward-looking statements describe our future plans, objectives, expectations or goals. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, no assurances can be given that these expectations will prove to be correct. Such statements address future events and conditions and include, but are not limited to:
capital expenditures,
earnings,
liquidity and capital resources,
ratemaking/regulatory matters,
litigation,
accounting matters,
possible corporate restructurings, acquisitions and dispositions,
compliance with debt and other restrictive covenants,
interest rates and dividends,
environmental matters,
nuclear operations, and
the overall economy of our service area.
These forward-looking statements are based on assumptions and analyses in light of the Company's experience and perception of historical trends, current conditions, expected future developments and other factors the Company believes were appropriate in the circumstances when the statements were made. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly impact expected results, and actual future results could differ materially from those described in such statements. While it is not possible to identify all factors, the Company continues to face many risks and uncertainties. Factors that would cause or contribute to such differences include, but are not limited to:
actions of our regulators,
our ability to fully and timely recover our costs and earn a reasonable rate of return on our invested capital through the rates that we are permitted to charge,
rates, cost recovery mechanisms and other regulatory matters including the ability to recover fuel costs on a timely basis,
the ability of our operating partners to maintain plant operations and manage operation and maintenance costs at the Palo Verde and Four Corners plants, including costs to comply with any new or expanded regulatory or environmental requirements,
reductions in output at generation plants operated by us,
the size of our construction program and our ability to complete construction on budget and on time,
our reliance on significant customers,
the credit worthiness of our customers,
unscheduled outages of generating units including outages at Palo Verde,
changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging competing services and technologies, including distributed generation,
individual customer groups, including distributed generation customers, may not pay their full cost of service, and other customers may or may not be required to pay the difference,

               
 
( iii)
 


changes in, and the assumptions used for, pension and other post-retirement and post-employment benefit liability calculations, as well as actual and assumed investment returns on pension plan and other post-retirement plan assets,
the impact of changing cost escalation and other assumptions on our nuclear decommissioning liability for Palo Verde, as well as actual and assumed investment returns on decommissioning trust fund assets,
disruptions in our transmission system, and in particular the lines that deliver power from our remote generating facilities,
electric utility deregulation or re-regulation,
regulated and competitive markets,
ongoing municipal, state and federal activities,
cuts in military spending or shutdowns of the federal government that reduce demand for our services from military and governmental customers,
political, legislative, judicial and regulatory developments,
homeland security considerations, including those associated with the U.S./Mexico border region and the energy industry,
changes in environmental laws and regulations and the enforcement or interpretation thereof, including those related to air, water or greenhouse gas ("GHG") emissions or other environmental matters,
economic and capital market conditions,
changes in accounting requirements and other accounting matters,
changing weather trends and the impact of severe weather conditions,
possible physical or cyber attacks, intrusions or other catastrophic events,
the impact of lawsuits filed against us,
the impact of changes in interest rates,
Texas, New Mexico and electric industry utility service reliability standards,
coal, uranium, natural gas, oil and wholesale electricity prices and availability,
possible income tax and interest payments as a result of audit adjustments proposed by the Internal Revenue Service ("IRS") or state taxing authorities,
the impact of U.S. health care reform legislation,
loss of key personnel, our ability to recruit and retain qualified employees and our ability to successfully implement succession planning, and
other circumstances affecting anticipated operations, sales and costs.
These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this document under the headings "Risk Factors" and "Management’s Discussion and Analysis" "–Summary of Critical Accounting Policies and Estimates" and "–Liquidity and Capital Resources." This Annual Report on Form 10-K should be read in its entirety. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. Any forward-looking statement speaks only as of the date such statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made, except as required by applicable laws or regulations.
 


               
 
( iv)
 


PART I
 
Item 1.
Business
General
El Paso Electric Company (the "Company") is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a full requirements wholesale customer in Texas. The Company owns or has significant ownership interests in several electrical generating facilities providing it with a net dependable generating capability of approximately 2,055 MW. For the year ended December 31, 2015, the Company’s energy sources consisted of approximately 47% nuclear fuel, 34% natural gas, 6% coal, 13% purchased power and less than 1% generated by Company-owned solar photovoltaic panels and wind turbines. The Company continues to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. As of December 31, 2015, the Company has power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources- Purchased Power").
The Company serves approximately 404,500 residential, commercial, industrial, public authority and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 63% and 12%, respectively, of the Company’s retail revenues for the year ended December 31, 2015). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public authority and other large retail customers of the Company include United States military installations, including Fort Bliss in Texas and White Sands Missile Range ("White Sands") and Holloman Air Force Base ("HAFB") in New Mexico, an oil refinery, several medical centers, two large universities and a steel production facility.
The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone 915-543-5711). The Company was incorporated in Texas in 1901. As of January 31, 2016, the Company had approximately 1,100 employees, 38% of whom are covered by a collective bargaining agreement.
The Company makes available free of charge through its website, www.epelectric.com, its Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statement, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission ("SEC"). In addition, copies of the Annual Report will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov. The information on the Company's website is not incorporated by reference into this Annual Report.
Facilities
As of December 31, 2015, the Company’s net dependable generating capability of 2,055 MW consists of the following: 
Station
 
Primary Fuel
Type
 
Company's Share of Net
Dependable
Generating
Capability *
(MW)
Company Ownership Interest
Location
Newman Power Station
 
Natural Gas
 
752

100.0
%
El Paso, Texas
Palo Verde
 
Nuclear
 
633

15.8
%
Wintersburg, Arizona
Rio Grande Power Station
 
Natural Gas
 
321

100
%
Sunland Park, New Mexico
Montana Power Station (Units 1 and 2)
 
Natural Gas
 
176

100
%
El Paso, Texas
Four Corners (Units 4 and 5)
 
Coal
 
108

7
%
Fruitland, New Mexico
Copper Power Station
 
Natural Gas
 
64

100
%
El Paso, Texas
Renewables
 
Wind/Solar
 
1

100
%
Hudspeth/El Paso Counties, Texas; Dona Ana County, New Mexico
Total
 
 
 
2,055

 
 
____________________
* During summer peak period, the Company owned renewables include a wind ranch with a total capacity of 1.32 MW and six solar photovoltaic facilities with a total capacity of 0.2 MW.

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, 2015, the Company's decommissioning trust fund had a balance of $239.0 million. Although the 2013 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates attributable to the Company will not increase in the future or that regulatory requirements will not change.
Spent Fuel Storage. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the United States Department of Energy ("DOE") is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On August 18, 2014, APS and the DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by the DOE to the Palo Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received approximately $9.1 million, representing its share of the award. The majority of the award was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS acting on behalf of itself and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was $42.0 million. On June 1, 2015, the Company received approximately $6.6 million, representing its share of the award. The majority of the award was credited to customers through the applicable fuel adjustment clauses in March 2015. Thereafter APS will file annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. Funds related to this claim are expected to be received in the second quarter of 2016. The Company's share of this claim is approximately $1.9 million.
DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations by designing, licensing, constructing and operating a permanent geologic repository at Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE's authority to withdraw the Yucca Mountain construction authorization application and NRC’s cessation of its review of the Yucca Mountain construction authorization application. The cases have been consolidated into one matter at the U.S. Court of Appeals for the District of Columbia Circuit (the "D.C. Circuit"). In August 2013, the D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds.
On October 16, 2014, the NRC issued Volume 3 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume addresses repository safety after permanent closure, and its issuance is a key milestone in the Yucca Mountain licensing process. Volume 3 contains the

2


NRC staff’s finding that the DOE’s repository design meets the requirements that apply after the repository is permanently closed, including but not limited to the post-closure performance objectives in NRC’s regulations.
On December 18, 2014, the NRC issued Volume 4 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume covers administrative and programmatic requirements for the repository. It documents the NRC staff’s evaluation of whether the DOE’s research and development and performance confirmation programs, as well as other administrative controls and systems, meet applicable NRC requirements. Volume 4 contains the NRC staff’s finding that most administrative and programmatic requirements in NRC regulations are met, except for certain requirements relating to ownership of land and water rights.
Publication of Volumes 3 and 4 does not signal whether or when the NRC might authorize construction of the repository. The Company cannot predict when spent fuel shipments to the DOE will commence.
Waste Confidence. On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (“Waste Confidence Decision”).
The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which, consistent with the National Environmental Policy Act (“NEPA”), requires either an environmental impact statement or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action consistent with NEPA.
On September 6, 2012, the NRC Commissioners issued a directive to the NRC staff to proceed directly with development of a generic environmental impact statement to support an updated Waste Confidence Decision. The NRC Commissioners also directed the NRC staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.
In September 2013, the NRC issued its draft Generic Environmental Impact Statement (“GEIS”) to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. The continued storage rule adopted the findings of the GEIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although Palo Verde has not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the Court of Appeals.
Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.
NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. The NRC regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee's safety performance. Following the March 11, 2011 earthquake and tsunami in Japan, the NRC established a task force to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system. On March 12, 2012, the NRC issued the first regulatory requirements based on the recommendations of the NRC's Near Term Task Force. With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants; and (2) enhancement of spent fuel pool instrumentation.
The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Palo Verde has met the NRC's imposed deadlines for installation of equipment to address these requirements,

3


but has minor additional work to perform in 2016. Palo Verde has spent approximately $125 million (the Company's share is $19.7 million) on capital enhancements related to these requirements as of December 31, 2015.
Liability and Insurance Matters. The Palo Verde Participants have insurance for public liability resulting from nuclear energy hazards, covered by primary liability insurance provided by commercial insurance carriers and an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis up to $60.4 million, with an annual payment limitation of approximately $9.0 million. The Palo Verde Participants also maintain $2.8 billion of "all risk" nuclear property insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage limit is $2.25 billion. In addition, the Company has secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo Verde.
Fossil-Fueled Plants
The Newman Power Station consists of three conventional steam-electric generating units and two combined cycle generating units. The station operates primarily on natural gas but the conventional steam-electric generating units can also operate on fuel oil.
The Company's Rio Grande Power Station consists of three conventional steam-electric generating units and one aeroderivative unit that operate on natural gas.
The Company's Montana Power Station ("MPS") consists of two aeroderivative generating units which operate on natural gas.
The Company's Copper Power Station consists of a natural gas combustion turbine used primarily to meet peak demand.
The Company owns a 7% interest in Units 4 and 5 at Four Corners. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. Four Corners is a coal-fired generating facility that is located on land under easements from the federal government and a lease from the Navajo Nation that expires in July of 2016. APS, on behalf of the Four Corners participants, negotiated amendments to the lease with the Navajo Nation which extended the lease from 2016 to 2041.
The Company notified the other participants in 2013 that it would not continue in Four Corners after the termination of the 50-year contractual term of the participation agreement in July 2016 but that it would offer to sell its interest to them in order to facilitate their decision to extend the life of the plant. On February 17, 2015, the Company and APS entered into an asset purchase agreement (the "Purchase and Sale Agreement") providing for the purchase by APS of the Company’s interests in Four Corners. The cash purchase price is equal to the net book value of the Company’s interest in Four Corners at the date of closing. The anticipated closing date for the sale is July 6, 2016, pending regulatory approval. The purchase price will be adjusted downward to reflect APS’s assumption in the Agreement of the Company’s obligation to pay for future plant decommissioning and mine reclamation expenses. At the closing, APS will also reimburse the Company for the undepreciated value of certain capital expenditures made prior thereto. APS will assume responsibility for all capital expenditures made after July 2016 and, with certain exceptions, any pre-2016 capital expenditures to be put into service following the closing. In addition, APS will indemnify the Company against liabilities and costs related to the future operation of Four Corners.
Wind and Solar Photovoltaic Facilities
The Company’s Hueco Mountain Wind Ranch consists of two wind turbines with a total capacity of 1.32 MW. The Company also owns six solar photovoltaic facilities with a total capacity of 0.2 MW.
Transmission and Distribution Lines and Agreements
The Company owns, or has significant ownership interests in, four 345 kV transmission lines in New Mexico and Arizona and three 500 kV lines in Arizona. These lines enable the Company to deliver its energy entitlements from its remote generation sources at Palo Verde and Four Corners to its service area (pursuant to various transmission and power exchange agreements to which the Company is a party). The Company also owns the transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. Pursuant to standards established by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, the Company

4


operates its transmission system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service.
In addition to the transmission and distribution lines within our service territory, the Company's transmission network and associated substations include the following:

Line
 
Length (miles)
 
Voltage (kV)
 
Company Ownership Interest
Springerville-Macho Springs-Luna-Diablo Line (1)
 
310

 
345

 
100.0
%
West Mesa-Arroyo Line (2)
 
202

 
345

 
100.0
%
Greenlee-Hidalgo-Luna-Newman Line (3)
 
 
 
 
 
 
Greenlee-Hidalgo
 
60

 
345

 
40.0
%
Hidalgo-Luna
 
50

 
345

 
57.2
%
Luna-Newman
 
86

 
345

 
100.0
%
Eddy County-AMRAD Line (4)
 
125

 
345

 
66.7
%
Palo Verde Transmission
 
 
 
 
 
 
Palo Verde-Westwing (5)
 
45

 
500

 
18.7
%
Palo Verde-Jojoba-Kyrene (6)
 
75

 
500

 
18.7
%
____________________
(1)
Runs from Tucson Electric Power Company ("TEP") Springerville Generating Plant near Springerville, Arizona, to the Company's Diablo Substation near Sunland Park, New Mexico.
(2)
Runs from Public Service Company of New Mexico ("PNM") West Mesa Substation located near Albuquerque, New Mexico, to the Company's Arroyo Substation located near Las Cruces, New Mexico.
(3)
Runs from TEP's Greenlee Substation near Duncan, Arizona to the Newman Power Station.
(4) Runs from the Company's and PNM's high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico.
(5)
Represents two 45-mile, 500 kV lines running from Palo Verde to the Westwing Substation located northwest of Phoenix near Peoria, Arizona.
(6) Runs from Palo Verde to the Jojoba Substation located near Gila Bend, Arizona, then to the Kyrene Substation located near Tempe, Arizona.
Environmental Matters
The Company is subject to extensive laws, regulations and permit requirements with respect to air and GHG emissions, water discharges, soil and water quality, waste management and disposal, natural resources and other environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation, or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to comply.
See Part II, Item 8, Financial Statements and Supplementary Data, Note K for more information regarding environmental risks, laws and regulations and legal proceedings for which we are and maybe subject to in the future.
Construction Program
Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems, and the cost of capital improvements and replacements at Palo Verde. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system and to replace retiring plants and terminated purchased power agreements, the costs of which are included in the table below.
The Company’s estimated cash construction costs for 2016 through 2020 are approximately $1.1 billion. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.

5


 
    
By Year (1)(2)
(estimates in millions)
 
By Function
(estimates in millions)
2016
$
231

 
Production (1)(2)
$
534

2017
156

 
Transmission
113

2018
182

 
Distribution
323

2019
232

 
General
114

2020
283

 
 
 
Total
$
1,084

 
Total
$
1,084

__________________________
(1)
Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel."
(2)
Estimated production costs consist of:
a.
$307 million for new generating capacity, including:
i.
$32 million for MPS of which $25 million is to complete construction of two 88 MW gas-fired LMS-100 units (3 and 4) that are scheduled to come on line in May and December of 2016, respectively.
ii.
$254 million of construction costs from 2018 through 2020 for two combined cycle units scheduled to be completed in 2022 and 2024.
iii.
$21 million for two utility-scale solar energy generating facilities, which would have a combined maximum capacity up to 8 MW.
b.
$227 million of other generation costs, including $189 million for Palo Verde.





6


Energy Sources
General
The following table summarizes the percentage contribution of nuclear fuel, natural gas, coal and purchased power to the total kWh energy mix of the Company. Energy generated by Company-owned solar photovoltaic panels and wind turbines accounted for less than 1% of the total kWh energy mix.
        
 
Years Ended December 31,
 
2015
 
2014
 
2013
Power Source
(percentage of energy mix)
Nuclear
47
%
 
47
%
 
46
%
Natural gas
34

 
35

 
34

Coal
6

 
5

 
6

Purchased power
13

 
13

 
14

Total
100
%
 
100
%
 
100
%
Allocated fuel and purchased power costs are generally recoverable from customers in Texas and New Mexico pursuant to applicable regulations. Historical fuel costs and revenues are reconciled periodically in proceedings before the Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC"). See "Regulation – Texas Regulatory Matters" and "– New Mexico Regulatory Matters."
Nuclear Fuel    
The nuclear fuel cycle for Palo Verde consists of the following stages:  the mining and milling of uranium ore to produce uranium concentrates, the conversion of the uranium concentrates to uranium hexafluoride ("conversion services"), the enrichment of uranium hexafluoride ("enrichment services"), the fabrication of fuel assemblies ("fabrication services"), the utilization of the fuel assemblies in the reactors, and the storage and disposal of the spent fuel. 
Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Palo Verde Participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The Palo Verde Participants have contracted for 100% of Palo Verde's requirements for uranium concentrates and conversion services through 2018 and 45% of its requirements in 2019-2021. The participants have also contracted for 100% of Palo Verde's enrichment services through 2020 and all of Palo Verde's fuel assembly fabrication services through 2022. 
Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust ("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. RGRT has $95 million aggregate principal amount borrowed in the form of senior notes. The Company guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing requirements of RGRT are met with a combination of the senior notes and short-term borrowings under the revolving credit facility (the "RCF").
Natural Gas
The Company manages its natural gas requirements through a combination of a long-term (greater than a year) supply contract, several medium-term (greater than a month but less than one year) supply contracts and spot or short-term (daily to a month) market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. Medium-term and spot agreements are either fixed priced and/or index priced depending on the market. In 2015, the Company’s natural gas requirements at the Newman, Rio Grande and MPS were met with short-term, medium-term and long-term natural gas purchases from various suppliers, and this practice is expected to continue in 2016. Interstate gas is delivered under a base firm transportation contract. The Company has expanded its firm interstate transportation contract to include MPS. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for Newman, Rio Grande and MPS. The Company will continue to evaluate the availability of short-term natural gas supplies versus medium and long-term supplies to maintain a reliable and economical supply for its local generating stations.
Natural gas for the Newman and Copper Power Stations is also supplied pursuant to a long-term intrastate natural gas contract that became effective October 1, 2009 and continues through 2017.


7


Coal
APS, as operating agent for Four Corners, purchases Four Corners' coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation.
On December 30, 2013, APS and Southern California Edison ("SCE") closed their previously announced transaction whereby APS agreed to purchase SCE's 48% interest in Units 4 and 5 of Four Corners. Concurrently with the closing of this transaction, the ownership of BHP Navajo Coal Company, the coal supplier and operator of the mine that serves Four Corners, was transferred to Navajo Transitional Energy Company, LLC ("NTEC"), a company formed by the Navajo Nation to own the mine and develop other energy projects.
The Company notified the other participants in 2013 that it would not continue in Four Corners after the termination of the 50-year contractual term of the participation agreement in July 2016 but that it would offer to sell its interest to them in order to facilitate their decision to extend the life of the plant. On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by APS of the Company’s interests in Four Corners. The cash purchase price is equal to the net book value of the Company’s interest in Four Corners at the date of closing. The anticipated closing date for the sale is July 6, 2016, pending regulatory approval. The purchase price will be adjusted downward to reflect APS’s assumption in the Agreement of the Company’s obligation to pay for future plant decommissioning and mine reclamation expenses. At the closing, APS will also reimburse the Company for the undepreciated value of certain capital expenditures made prior thereto. APS will assume responsibility for all capital expenditures made after July 2016 and, with certain exceptions, any pre-2016 capital expenditures to be put into service following the closing. In addition, APS will indemnify the Company against liabilities and costs related to the future operation of Four Corners.
Purchased Power
To supplement its own generation and operating reserve requirements, and to meet required renewable portfolio standards, the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the Company’s resource needs, the economics of the transactions and specific renewable portfolio requirements.
The Company has a firm 100 MW Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport") that provides for Freeport to deliver energy to the Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to the contracted MW amount at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. The agreement was approved by the Federal Energy Regulatory Commission ("FERC") and will continue through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold under the agreement. The parties have agreed to increase the amount to 125 MW through December 2016.
The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements. Specifically, the Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico, which began commercial operation in July 2011. In June 2015, the Company entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement photovoltaic modules. The Company also entered into a 20-year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico, which began commercial operation in August 2011. In addition, the Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunE EPE1, LLC (10 MW) and SunE EPE2, LLC (12 MW), which began commercial operation in June 2012 and May 2012, respectively.
Furthermore, the Company has a 20-year purchase power agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico which began commercial operation in May 2014. Finally, the Company has a 30-year purchase power agreement with Newman Solar LLC to purchase the total output of approximately 10 MW from a solar photovoltaic generation plant on land subleased from the Company in proximity to its Newman Generation Station. This solar project began commercial operation in December 2014.
Other purchases of shorter duration were made during 2015 to supplement the Company's generation resources during planned and unplanned outages, for economic reasons, and to supply off-system sales.

8


Operating Statistics
 
Years Ended December 31,
 
2015
 
2014
 
2013
Operating revenues (in thousands):
 
 
 
 
 
Non-fuel base revenues:
 
 
 
 
 
Retail:
 
 
 
 
 
Residential
$
246,265

 
$
234,371

 
$
236,651

Commercial and industrial, small
187,436

 
185,388

 
184,568

Commercial and industrial, large
40,411

 
39,239

 
40,235

Sales to public authorities
91,244

 
92,066

 
95,044

Total retail base revenues
565,356

 
551,064

 
556,498

Wholesale:
 
 
 
 
 
Sales for resale
2,455

 
2,277

 
2,172

Total non-fuel base revenues
567,811

 
553,341

 
558,670

Fuel revenues:
 
 
 
 
 
Recovered from customers during the period
127,765

 
161,052

 
133,481

Under (over) collection of fuel
(13,342
)
 
3,110

 
10,849

New Mexico fuel in base rates
72,129

 
71,614

 
73,295

Total fuel revenues
186,552

 
235,776

 
217,625

Off-system sales:
 
 
 
 
 
Fuel cost
52,406

 
74,716

 
68,241

Shared margins
11,048

 
21,117

 
13,016

Retained margins
1,362

 
2,147

 
1,549

Total off-system sales
64,816

 
97,980

 
82,806

Other
30,690

 
30,428

 
31,261

Total operating revenues
$
849,869

 
$
917,525

 
$
890,362

Number of customers (end of year) (1):
 
 
 
 
 
Residential
358,819

 
353,885

 
349,629

Commercial and industrial, small
40,367

 
40,038

 
39,164

Commercial and industrial, large
49

 
49

 
50

Other
5,261

 
5,017

 
5,043

Total
404,496

 
398,989

 
393,886

Average annual kWh use per residential customer
7,763

 
7,496

 
7,701

Energy supplied, net, kWh (in thousands):
 
 
 
 
 
Generated
9,585,089

 
9,477,129

 
9,288,773

Purchased and interchanged
1,390,946

 
1,390,490

 
1,547,930

Total
10,976,035

 
10,867,619

 
10,836,703

Energy sales, kWh (in thousands):
 
 
 
 
 
Retail:
 
 
 
 
 
Residential
2,771,138

 
2,640,535

 
2,679,262

Commercial and industrial, small
2,384,514

 
2,357,846

 
2,349,148

Commercial and industrial, large
1,062,662

 
1,064,475

 
1,095,379

Sales to public authorities
1,585,568

 
1,562,784

 
1,622,607

Total retail
7,803,882

 
7,625,640

 
7,746,396

Wholesale:
 
 
 
 
 
Sales for resale
63,347

 
61,729

 
61,232

Off-system sales
2,500,947

 
2,609,769

 
2,472,622

Total wholesale
2,564,294

 
2,671,498

 
2,533,854

Total energy sales
10,368,176

 
10,297,138

 
10,280,250

Losses and Company use
607,859

 
570,481

 
556,453

Total
10,976,035

 
10,867,619

 
10,836,703

Native system:
 
 
 
 
 
Peak load, kW
1,794,000

 
1,766,000

 
1,750,000

Net dependable generating capability for peak, kW
2,055,000

 
1,879,000

 
1,852,000

Total system:
 
 
 
 
 
Peak load, kW (2)
1,992,000

 
1,953,000

 
1,883,000

Net dependable generating capability for peak, kW
2,055,000

 
1,879,000

 
1,852,000

___________________________
(1)
The number of retail customers presented is based on the number of service locations.
(2)
Includes spot sales and net losses of 198,000 kW, 187,000 kW and 133,000 kW for 2015, 2014 and 2013, respectively.

9


Regulation
General
The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. Municipal orders, ordinances and other agreements regarding rates and services adopted by Texas municipalities are subject to review and approval by the PUCT. The FERC has jurisdiction over the Company's wholesale (sales for resale) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and the FERC are subject to judicial review.
Texas Regulatory Matters
2012 Texas Retail Rate Case. On April 17, 2012, the El Paso City Council approved the settlement of the Company's 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094. The PUCT issued a final order approving the settlement on May 23, 2012 and the rates were effective as of May 1, 2012. As part of the 2012 Texas retail rate settlement, the Company agreed to submit a future fuel reconciliation request covering the period beginning July 1, 2009 and ending no later than June 30, 2013 by December 31, 2013 or as part of its next rate case, if earlier. The Company filed a fuel reconciliation request covering the period July 1, 2009 through March 31, 2013, as discussed below. The 2012 Texas retail rate settlement also provided for the continuation of the energy efficiency cost recovery factor and the military base discount recovery factor. Both of these surcharges require annual filings to reconcile and revise the recovery factors.
2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities incorporated in its Texas service territory, and the PUCT in Docket No. 44941, a request for an increase in non-fuel base revenues of approximately $71.5 million. The request includes recovery of new plant placed into service since 2009 . On January 15, 2016, the Company filed its rebuttal testimony modifying the requested increase to $63.3 million. The Company has invoked its statutory right to have its new rates relate back for consumption on and after January 12, 2016, which is the 155th day after the filing. The difference in rates that would have been collected will be surcharged or refunded to customers beginning after the PUCT's final order in Docket No. 44941, which is expected to be in the second quarter of 2016. The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. On January 21, 2016, the Company, the City of El Paso, the PUCT staff, the Office of Public Utility Counsel and the Texas Industrial Energy Consumers filed a joint motion to abate the procedural schedule to facilitate settlement talks. This motion was granted. The Company cannot predict the outcome of the rate case at this time.
Energy Efficiency Cost Recovery Factor. The Company made its annual filing to establish its energy efficiency cost recovery factor for 2015 on May 1, 2014. In addition to projected energy efficiency costs for 2015 and true-up to prior year actual costs, the Company requested approval of a $2.0 million bonus for the 2013 energy efficiency program results in accordance with PUCT rules. The PUCT approved the Company's request at its November 14, 2014 open meeting. The Company recorded the $2.0 million bonus as operating revenue in the fourth quarter of 2014.
On May 1, 2015, the Company made its annual filing to establish its energy efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and true-up to prior year actual costs, the Company requested approval of a $1.0 million bonus for the 2014 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 44677. A stipulation and settlement agreement was filed September 24, 2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT includes a performance bonus of $1.0 million. The Company recorded the performance bonus as operating revenue in the fourth quarter of 2015.
Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.
On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the PUCT's materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the

10


PUCT on May 20, 2015. As of December 31, 2015, the Company had over-recovered fuel costs in the amount of $0.1 million for the Texas jurisdiction.
Fuel Reconciliation Proceeding. Pursuant to the 2012 Texas retail rate settlement discussed above, on September 27, 2013, the Company filed an application with the PUCT, designated as PUCT Docket No. 41852, to reconcile $545.3 million of fuel and purchased power expenses incurred during the 45-month period from July 1, 2009 through March 31, 2013. A settlement was reached and a final order was issued by the PUCT on July 11, 2014. The PUCT's final order completes the regulatory review and reconciliation of the Company's fuel expenses for the period through March 31, 2013. The Company is required to file an application in 2016 for fuel reconciliation of the Company’s fuel expenses for the period through March 31, 2016.
Montana Power Station Approvals. The Company has received a Certificate of Convenience and Necessity ("CCN") from the PUCT to construct four natural gas fired generating units at MPS in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the U.S. Environmental Protection Agency (the "EPA"). MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in March 2015.
Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program to include construction and ownership of a 3 MW solar photovoltaic system located at MPS. Participation will be on a voluntary basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT Docket No. 44800. The Company presented the other parties a proposed structure for settlement of this proceeding and the other parties are in the process of evaluating it.
Four Corners. On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by APS of the Company's interests in Four Corners. The Purchase and Sale Agreement included a projected cash purchase price which will be equal to the net book value of our interest in Four Corners at the date of close. The net book value at June 30, 2016 is expected to approximate $20 million. The Company will also be reimbursed for certain undepreciated capital expenditures, that are projected to approximate $10 million at June 30, 2016. The purchase price will be adjusted downward to reflect APS's assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses estimated at July 6, 2016 to be $7.0 million and $19.3 million, respectively.
On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and certain rate and accounting findings related to the Purchase and Sale Agreement. The anticipated closing date of the sale is July 6, 2016, pending regulatory approval. This case was assigned PUCT Docket No. 44805. It is expected that the final coal mine closing and reclamation costs, which the Company historically has been permitted to recover in its fuel recovery mechanism, will be addressed in the proceeding, as well as other issues related to post-participation events such as the ARO. On January 11, 2016, the PUCT referred the case to the State Office of Administrative Hearings ("SOAH") for an administrative hearing. On February 5, 2016, an administrative law judge ("ALJ") of the SOAH issued an order adopting a procedural schedule. The procedural schedule calls for a hearing on the merits to be held in the fourth quarter of 2016. At December 31, 2015 the regulatory asset associated with mine reclamation costs for our Texas jurisdiction approximates $7.6 million. At the PUCT's February 11, 2016 open meeting, Commissioners discussed whether the Company's application should be addressed in a rate case. On February 11, 2016, the PUCT issued its Order Requesting Briefing on Threshold Legal/Policy Issues, seeking briefs from the parties on the issue "Should the Commission dismiss this docket?" Such briefs were due by February 22, 2016. The PUCT is expected to consider that issue at its open meeting currently scheduled for March 3, 2016.
The Company currently continues to recover its mine reclamation costs in Texas under previous orders and decisions of the PUCT. If any future determinations made by our regulators result in changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions.
Other Required Approvals. The Company has obtained other required approvals for tariffs and approvals as required by the Public Utility Regulatory Act (the "PURA") and the PUCT.
New Mexico Regulatory Matters
2009 New Mexico Stipulation. On December 10, 2009, the NMPRC issued a final order conditionally approving the stipulated rates in NMPRC Case No. 09-00171-UT. The stipulated rates went into effect with January 2010 bills. The stipulated rates provide for an Efficient Use of Energy Factor Rate Rider to recover energy efficiency expenditures, which are updated annually for adjustment to the recovery factors.
2015 New Mexico Rate Case Filing. On May 11, 2015, the Company filed with the NMPRC (NMPRC Case No. 15-00127-UT) for an annual increase in non-fuel base rates of approximately $8.6 million or 7.1%. The request includes recovery of new

11


plant placed into service since the last time rates were adjusted in 2009. The filing also requests an annual reduction of $15.4 million, or 21.5%, for fuel and purchased power costs recovered in base rates. The reduction in fuel and purchased power rates reflects reduced fuel prices and improvements in system heat rates due to new generating unit additions. Subsequently, the Company reduced its requested increase in non-fuel base rates to approximately $6.4 million On February 16, 2016, the Hearing Examiner issued a Recommended Decision to the NMPRC proposing an annual increase in non-fuel base rates of approximately $640 thousand. On February 17, 2016, the NMPRC issued an order extending the suspension period in the rate case from March 10, 2016 until April 8, 2016, by which time the NMPRC is expected to either issue a final order with new rates to go into effect in the second quarter of 2016 or again extend the suspension period further to as late as June 10, 2016. All parties will be allowed to file exceptions before the NMPRC ultimately rules on the issues by final order. The Company cannot predict the outcome of the rate case at this time.
Fuel and Purchased Power Costs. Fuel and purchased power costs are recovered through base rates and a Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") that accounts for changes in the costs of fuel relative to the amount included in base rates. On January 8, 2014, the NMPRC approved the continuation of the FPPCAC without modification in NMPRC Case No. 13-00380-UT. Fuel and purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the FPPCAC as purchased power using a proxy market price approved in the 2014 FPPCAC continuation. At December 31, 2015, we had a net fuel over-recovery balance of $3.8 million in New Mexico.
Montana Power Station Approvals. The Company has received a CCN from the NMPRC to construct four units at MPS and the associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the EPA. A final order in NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and MPS to Caliente and MPS In & Out transmission lines were completed and placed into service in March 2015.
Four Corners Generating Station ("Four Corners"). On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by APS of the Company's interests in Four Corners. On April 27, 2015, the Company filed an application requesting all necessary regulatory approvals to sell its ownership interest in Four Corners. The anticipated closing date of the sale is July 6, 2016, pending regulatory approval. This case was assigned NMPRC Case No. 15-00109-UT. On February 2, 2016, the Company filed a joint stipulation with the NMPRC reflecting a settlement agreement among the Commission Utility Division Staff, the Company and the New Mexico Attorney General proposing approval of abandonment and sale of its seven percent minority ownership interest in Four Corners Units 4 and 5 and common facilities to APS. An addendum to the joint stipulation was subsequently filed to include non-opposition by other non-stipulating parties. A hearing in the case was held on February 16, 2016, and a final order approving the joint stipulation is expected in the first half of 2016. Based on the joint stipulation and addendum, no significant gain or loss is expected to be realized upon closing of the sale.
5 MW HAFB Facility CCN. On June 15, 2015, the Company filed a petition with the NMPRC requesting CCN authorization to construct a 5 MW solar-powered generation facility to be located at HAFB in the Company's service territory in New Mexico. The new facility will be a dedicated Company-owned resource serving HAFB. This case was assigned NMPRC Case No. 15-00185-UT. On October 7, 2015, the NMPRC issued a Final Order accepting the Hearing Examiner’s Recommended Decision to approve the CCN, as modified, that the Company shall not seek to recover any revenue requirement associated with the facility from New Mexico jurisdictional customers other than HAFB without prior NMPRC approval.
Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case No. 15-00280-UT to issue up to $310 million in new long-term debt; and to guarantee the issuance of up to $65 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval supersedes prior approvals.
Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC.

12


Federal Regulatory Matters
Four Corners. On June 26, 2015, APS filed an application requesting authorization from FERC to purchase 100% of the Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and rights. On December 22, 2015, FERC issued an order approving the proposed transaction.
PNM Transmission Rate Case. On December 31, 2012, PNM filed with FERC to change its method of transmission rate recovery  for its transmission delivery services from stated rates to  formula rates.  The Company takes transmission service from PNM and is among the PNM transmission customers affected by PNM’s shift to formula rates. On March 1, 2013, the FERC issued an order rejecting in part PNM’s filing, and establishing settlement judge and hearing procedures. On March 20, 2015, PNM filed with FERC a settlement agreement and offer of settlement resolving all issues set for hearing in the proceeding. On March 25, 2015, the Chief Judge issued an order granting PNM's motion to implement the settled rates. However, the Company is still awaiting a final decision from the FERC on whether the settlement will be approved. The Company cannot predict the outcome of the case at this time.
Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under its existing revolving credit facility up to $400 million outstanding at any time, to issue up to $310 million in long-term debt, and to guarantee the issuance of up to $65 million of new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from November 15, 2015 through November 15, 2017. This approval supersedes prior approvals.
Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC.
Department of Energy. The DOE regulates the Company's exports of power to the Comisión Federal de Electricidad in Mexico pursuant to a license and two presidential permits issued by the DOE.
The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Facilities-Palo Verde for discussion of spent fuel storage and disposal costs.

Sales for Resale
The Company provides firm capacity and associated energy to the Rio Grande Electric Cooperative ("RGEC") pursuant to an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission service to the RGEC pursuant to the Company's Open Access Transmission Tariff ("OATT"). The contract includes a formula-based rate that is updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC.
Power Sales Contracts
The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2015.

13


Franchises and Significant Customers
Franchises
The Company operates under franchise agreements with several cities in its service territory, including one with El Paso, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its customers within El Paso. Pursuant to the El Paso franchise agreement amended in 2010, the Company pays to the City of El Paso, on a quarterly basis, a fee equal to 4.00% of gross revenues the Company receives for the generation, transmission and distribution of electrical energy and other services within the city. The 2005 El Paso franchise agreement set the franchise fee at 3.25% of gross revenues, but the 2010 Amendment added an incremental fee equal to 0.75% of gross revenues to be placed in a restricted fund to be used by the city solely for economic development and renewable energy purposes. Any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso. The El Paso franchise agreement is set to expire on July 31, 2030.
The Company does not have a written franchise agreement with the City of Las Cruces, the second largest city in its service territory. The Company provides electric distribution service to Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009. The Company pays the City of Las Cruces a franchise fee of 2.00% of gross revenues the Company receives from services within the City of Las Cruces.
Military Installations
The Company serves HAFB, White Sands and Fort Bliss. The military installations represent approximately 4% of the Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss for an initial three-year term under which Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company serves White Sands under the applicable New Mexico tariffs. In March 2006, the Company signed a contract with HAFB under which the Company provides retail electric service and limited wheeling services to HAFB for a ten-year term which expired in January 2016 HAFB and the Company agreed to extend the retail pricing provisions of the existing agreement during negotiations for a replacement contract. The contract was revised to include to allow for an extension of services under the existing agreement.
Other Information
Investors should note that we announce material financial information in our filings with the SEC, press releases and public conference calls. Based on guidance from the SEC, we may also use the Investor Relations section of our website (www.epelectric.com) to communicate with investors about the Company. It is possible that the financial information we post there could be deemed to be material information. The information contained on or accessible from our website is not incorporated by reference into and does not constitute a part of this Annual Report on Form 10-K.        

14


Item 1A.    Risk Factors
Like other companies in our industry, our financial results are impacted by weather, the economy of our service territory, market prices for power, fuel prices, and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by local, regional and national macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.
Our Revenues and Profitability Depend Upon Regulated Rates
Our retail rates are subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. The settlement approved in the Company's 2012 Texas rate case, PUCT Docket No. 40094, established the Company's current retail base rates in Texas, effective May 1, 2012. In addition, the settlement in the Company's 2009 New Mexico rate case, NMPRC Case No. 09‑00171‑UT, established rates in New Mexico that became effective in January 2010.
Our profitability depends on our ability to recover the costs, including a reasonable return on invested capital, of providing electric service to our customers through base rates approved by our regulators. These rates are generally established based on an analysis of the expenses we incur in a historical test year, and as a result, the rates ultimately approved by our regulators may or may not match our expenses at any given time and recovery of expenses may lag behind the occurrence of those expenses. Rates in New Mexico may be established using projected costs and investment for a future test year period in certain instances. While rate regulation is based on the assumption that we will have a reasonable opportunity to recover our costs and earn a reasonable rate of return on our invested capital, there can be no assurance that our future Texas rate cases or New Mexico rate cases will result in base rates that will allow us to fully recover our costs including a reasonable return on invested capital. There can be no assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including costs associated with future plant retirement and ARO. It is also likely that third parties will intervene in any rate cases and challenge whether our costs are reasonable and necessary. If all of our costs are not recovered through the retail base rates ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely affect our ability to meet our financial obligations.

On May 11, 2015 and August 10, 2015, the Company filed a general rate case with the NMPRC, Case No. 15-00127-UT (the “2015 New Mexico rate case”) and the PUCT, Docket No. 44941 (the “2015 Texas rate case”), respectively, to establish new rates and to request recovery of new plant placed into service since 2009. Third parties have intervened in both rate cases and have challenged whether certain of our costs are reasonable and necessary. The Company anticipates a resolution of both the 2015 New Mexico rate case and the 2015 Texas rate case in the first or second quarter of 2016. If the NMPRC and PUCT do not increase the Company’s rates adequately, the Company’s future operations, cash flow and financial condition could be materially adversely affected. For a full discussion of these rate cases see Part II, Item 8, Financial Statements and Supplementary Data, Note C.
We May Not Be Able To Recover All Costs of New Generation and Transmission Assets
In 2013 and 2014, we received approval, both from the PUCT and the NMPRC, to construct four 88 MW simple-cycle aeroderivative combustion turbines at our MPS, a new plant site. During 2013, we completed the construction of Rio Grande Unit 9, an aeroderivative unit with a generating capacity of 87 MW, which reached commercial operation in May 2013. In 2015, we completed construction of MPS Units 1 and 2 which began commercial operation in March 2015. We have risk related to recovering all costs associated with the construction of Rio Grande Unit 9, MPS, and other new units and transmission assets.
In 2014, we issued $150 million in aggregate principal amount of 5.00% Senior Notes, due December 1, 2044. The net proceeds from the 5.00% Senior Notes along with borrowings under our RCF were used to fund the construction of MPS and other capital additions. The costs of financing and constructing these assets are being reviewed in the current Texas and New Mexico rate cases. To the extent that the PUCT or the NMPRC determines that the costs of construction are not reasonable because of cost overruns, delays or other reasons, we may not be allowed to recover these costs from customers in base rates.
In addition, if future units, such as MPS Units 3 and 4 are not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the PUCT and the NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting from delays in the completion of these new units or other new units.

15


Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital Programs and Increase Our Funding Obligations for Pensions and Decommissioning
In recent years, the global credit and equity markets and the overall economy have been extremely volatile. These and future events could have a number of effects on our operations and capital programs. For example, tight credit and capital markets could make it difficult and more expensive to raise capital to fund our operations and capital programs. If we are unable to access the credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in the stock market performance may reduce the value of our financial assets and decommissioning trust investments. Such market results may also increase our funding obligations for our pension plans, other post-retirement benefit plans and nuclear decommissioning trusts. Changes in the corporate interest rates that we use as the discount rate to determine our pension and other post-retirement liabilities may have an impact on our funding obligations for such plans and trusts. Further, continued economic volatility may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. Uncertainty in the credit markets may negatively impact the ability of our customers to finance purchases of our services and could adversely affect the collectability of our receivables. Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. For example, during 2013, sales to public authorities and small commercial and industrial customers were negatively impacted by the federal government sequestration and shutdown. The credit markets and overall economy may also adversely impact the financial health of our suppliers. If that were to occur, our access to and prices for inventory, supplies and capital equipment could be adversely affected. Our power trading counterparties could also be adversely impacted by the market and economic conditions which could result in reduced wholesale power sales or increased counterparty credit risk. Declines in revenues, earnings and cash flow from these events, could impact our ability to fund construction expenditures and impact the level of dividend payments.
There are Inherent Risks in the Ownership of Nuclear Facilities
Our 15.8% ownership interest in Palo Verde, which is the largest nuclear electric generating facility in the United States, subject us to a number of risks. A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 31% of our available net generating capacity and provided approximately 47% of our energy requirements for the twelve months ended December 31, 2015. Palo Verde comprises approximately 27% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and costs at Palo Verde. Palo Verde operated at a capacity factor of 94.3% and 93.7% in the twelve months ended December 31, 2015 and 2014, respectively.
As Palo Verde is a nuclear electric generating facility it is subject to environmental, health and financial risks, such as the ability to obtain adequate supplies of nuclear fuel; the ability to dispose of spent nuclear fuel; the ability to maintain adequate reserves for decommissioning; potential liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; cyber attacks, or other causes; and unscheduled outages due to equipment and other problems. If a nuclear incident were to occur at Palo Verde, it could materially and adversely affect our results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause regulatory bodies to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.
We May Not Be Able to Recover All of Our Fuel Expenses from Customers On a Timely Basis Or at All
In general, by law, we are entitled to recover our reasonable and necessary fuel and purchased power expenses from our customers in Texas and New Mexico. NMPRC Case No. 13-00380-UT provides for energy delivered to New Mexico customers from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon a previous purchased power contract. Fuel and purchased power expenses in New Mexico and Texas are subject to reconciliation by the PUCT and NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs such that fuel revenues equal recoverable fuel and purchased power expense including the repriced energy costs for Palo Verde Unit 3 in New Mexico. In the event that recovery of fuel and purchased power expenses is denied in any reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would incur a loss to the extent of the disallowance.
In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. In Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any

16


time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods of significant increases in natural gas prices, the Company realizes a lag in the ability to reflect increases in fuel costs in its fuel recovery mechanisms in Texas. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely recovery of such costs, we could experience a material negative impact on our cash flow.
Equipment Failures and Other External Factors Can Adversely Affect Our Results
The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure and severe weather conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these units. In the event of unplanned outages, we must acquire power from other sources at unpredictable costs in order to supply our customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to the extent of the disallowance. This could materially increase our costs and prevent us from selling excess power at wholesale. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We may also incur additional capital and operating costs in connection with the physical security and cyber security of transmission lines and generation facilities. Damage to certain transmission and generation facilities due to vandalism or other deliberate acts, or damage due to severe weather could lead to outages or other adverse effects. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde and Four Corners) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. In addition, Palo Verde’s availability is an important factor in realizing off-system sales margins. These factors, as well as interest rates, economic conditions, fuel prices and price volatility could have a material adverse effect on our earnings, cash flow and financial position.
Competition and Deregulation Could Result in a Loss of Customers and Increased Costs
As a result of changes in federal law, our wholesale and large retail customers have access to, in varying degrees, alternative sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. In 2004, the PUCT approved a rule delaying retail competition in our Texas service territory. This rule was codified in the PURA in June 2011. The PURA identifies various milestones that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization in the area that includes our service territory. This and other milestones are not likely to be achieved for a number of years, if at all. There is substantial uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flow and financial condition.
Future Costs of Compliance with Environmental Laws and Regulations Could
Adversely Affect Our Operations and Financial Results
We are subject to extensive federal, state and local environmental laws and regulations relating to discharges into the air, air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources, and health and safety.  Compliance with these legal requirements, which change frequently and often become more restrictive, could require us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchases of air emission allowances and/or offsets. These laws and regulations could also result in limitations in operating hours and/or changes in construction schedules for future generating units. 
Cost of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our rates, could adversely affect our operations and financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase.  We cannot estimate our compliance costs or any possible fines or penalties with certainty, or the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of implementation of environmental laws or regulations.  For example, the EPA has issued in the recent past various proposed regulations regarding air emissions, such as the revision of the primary and secondary ground-level ozone National Ambient Air

17


Quality Standards ("NAAQS"). If these regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our financial results.
Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for
Electricity or Availability of Resources, and Could Result in Increased Compliance Costs
The Company emits GHG (including carbon dioxide) through the operation of its power plants. Federal legislation had been introduced in both houses of Congress to regulate GHG emissions and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA. Under EPA regulations finalized in May 2010, formerly known as the "Tailoring Rule", the EPA can impose GHG best achievable control technology requirements for sources, including power plants already required to implement prevention of significant deterioration under the CAA for certain other pollutants.
In addition, in October 2015, the EPA published a final rule establishing new source performance standards ("NSPS") limiting CO2 emissions from new, modified and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February 9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. Further, the U.S. signed on to 21st Conference of Parties Paris Agreement signed on December 12, 2015, and indications are that the U.S. plans on relying heavily on the CPP to meet its early commitments. The potential impact of this Agreement and GHG rules (if and when finalized) on the Company is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or changes in construction schedules for future generating units.
It is not possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi-state regions or any GHG regulations adopted by the EPA or state environmental agencies will impact our business. However, any legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit GHG, and could have a material adverse effect on our business, financial condition, reputation or results of operations.
Adverse Regulatory Decisions or Changes in Applicable Regulations Could Have a Material Adverse Effect on Our
Business or Result in Significant Additional Costs

Our business is subject to extensive federal, state and local laws and regulations. FERC regulates the Company’s wholesale operations, provision of transmission services and compliance with federally mandated reliability standards. Additional regulatory authorities have jurisdiction over some of our operations and construction projects including the EPA, the DOE, the PUCT, the NMPRC and various local regulatory districts (including the cities of El Paso and Las Cruces).

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

Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our Infrastructure Could Interfere With Our Operations, Could Expose Us or Our Customers or Employees to a Risk of Loss, and Could Expose Us to Liability, Regulatory Penalties, Reputational Damage and Other Harm to Our Business

We rely upon our infrastructure to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology systems for internal accounting purposes and to comply with financial reporting, legal and tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers, breaches due to employee error or malfeasance, system failures, computer viruses, natural disasters, a physical attack on our facilities, or other catastrophic events. The occurrence of any of these events could impact the reliability of our generation, transmission and distribution systems and energy marketing and trading functions; could expose us or our customers or employees to a risk of loss or misuse of confidential information; and could result in legal claims or proceedings, liability or

18


regulatory penalties against us, damage our reputation or otherwise harm our business. In addition, we may be required to incur significant costs to prevent or respond to damage caused by these disruptions or security breaches in the future.
Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. The effects of such attacks against us or others in the energy industry could increase the cost of regulatory compliance, increase the cost of insurance coverage or result in a decline in the U.S. economy which could negatively affect our results of operations and financial condition. Ongoing and future governmental efforts to regulate cybersecurity in the energy industry could lead to increased regulatory compliance costs.
The Effects of Technological Advancement, Energy Conservation Measures and Distributed Generation Could Adversely Affect Our Operations and Financial Results
New technologies may emerge that could be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant expenditures to remain competitive. Our future success will depend, in part, on our ability to anticipate and adapt to technological changes in a cost-effective manner and to offer, on a timely basis, services that meet customer demands and evolving industry standards.
Additionally, the electric utility industry is undergoing other technological advances such as the expanded cost effective utilization of energy efficiency measures and distributed generation including solar rooftop projects. Customers’ increased use of energy efficiency measures and distributed generation could result in lower demand. Reduced demand due to energy efficiency measures and the use of distributed generation, to the extent not substantially offset through ratemaking mechanisms, could have a material adverse impact on our financial condition, results of operations and cash flows.
Provisions in Our Corporate Documents, Franchise Agreements and State Law Could Delay or Prevent a Change in Control of the Company, Even if That Change Would Be Beneficial to Our Shareholders

Our Articles of Incorporation and Bylaws contain provisions that may make acquiring control of the Company difficult and could preclude our shareholders from receiving a change of control premium, including:

provisions relating to the classification, nomination and removal of our directors;
provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;
provisions limiting the ability to call special meetings of the shareholders to the Chairman of the Board, our Chief Executive Officer, our Secretary, the majority of the Board of Directors or the holders of at least 25% of the outstanding shares of our capital stock entitled to vote at such meeting;
provisions restricting our ability to engage in a wide range of “Business Combination” transactions with an “Interested Shareholder” (generally, any person who owns 15% or more of our outstanding voting power) or any affiliate or associate of an Interested Shareholder, unless specific conditions are met; and
the authorization given to our Board of Directors or any duly designated committee to issue and set the terms of preferred stock.
Our El Paso franchise agreement states that any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso.

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



19


Item 1B.
Unresolved Staff Comments
None.


Item 2.
Properties
The principal properties of the Company are described in Item 1, "Business," and such descriptions are incorporated herein by reference. Transmission lines are located either on company-owned land, private rights-of-ways, easements, or on streets or highways by public consent.
The Company owns an executive and administrative office building and the Eastside Operations Center ( the "EOC"), which opened in early 2015, in El Paso County. The Company leases land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. The Company has several other leases for office and parking facilities that expire within the next five years.

Item 3.
Legal Proceedings
The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect on the financial position, results of operations or cash flows of the Company.
See Item 1, Business - Environmental Matters and Regulation, and Part II, Item 8, Financial Statements and Supplementary Data, Note C, Note L and Note K of Notes to Financial Statements" for discussion of the effects of government legislation and regulation on the Company as well as certain pending legal proceedings.

Item 4.
Mine Safety Disclosures

Not Applicable.


20


PART II
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
The Company’s common stock trades on the New York Stock Exchange ("NYSE") under the symbol "EE". The intraday high, intraday low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the NYSE, and quarterly dividends per share paid by the Company for the periods indicated below were as follows:
 
        
 
Sales Price
 
 
 
High
 
Low
 
Close
 
Dividends
 
 
 
 
 
(End of period)
 
 
2014
 
 
 
 
 
 
 
First Quarter
$
37.16

 
$
33.44

 
$
35.73

 
$
0.265

Second Quarter
40.33

 
35.21

 
40.21

 
0.280

Third Quarter
40.43

 
35.39

 
36.55

 
0.280

Fourth Quarter
42.17

 
35.34

 
40.06

 
0.280

2015
 
 
 
 
 
 
 
First Quarter
$
41.32

 
$
35.43

 
$
38.64

 
$
0.280

Second Quarter
39.26

 
33.77

 
34.66

 
0.295

Third Quarter
38.32

 
33.90

 
36.82

 
0.295

Fourth Quarter
40.35

 
35.32

 
38.50

 
0.295


21


Performance Graph
The following graph compares the performance of the Company’s common stock to the performance of Edison Electric Institute’s ("EEI") index of investor-owned electric utilities and the NYSE Composite, setting the value of each at December 31, 2010 to a base of 100. The table sets forth the relative yearly percentage change in the Company’s cumulative total shareholder return, assuming reinvestment of dividends, as compared to EEI and the NYSE Composite, as reflected in the graph.
 
12/31/2010
 
12/31/2011
 
12/31/2012
 
12/31/2013
 
12/31/2014
 
12/31/2015
EE
100

 
128

 
121

 
137

 
161

 
160

EEI Index
100

 
120

 
123

 
138

 
178

 
172

NYSE Composite
100

 
94

 
106

 
131

 
136

 
127

As of January 31, 2016, there were 2,437 holders of record of the Company’s common stock. The Company has been paying quarterly cash dividends on its common stock since June 30, 2011 and paid a total of $47.1 million in cash dividends during the twelve months ended December 31, 2015. On January 28, 2016, the Board of Directors declared a quarterly cash dividend of $0.295 per share payable on March 31, 2016 to shareholders of record on March 15, 2016. The Board of Directors plans to review the Company's dividend policy annually in the second quarter of each year.  Generally, we are targeting a payout ratio of approximately 45% to 55%. Declaration and payment of dividends is subject to compliance with certain financial tests under Texas law. Since 1999, the Company has also returned cash to stockholders through a stock repurchase program pursuant to which the Company has bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s program, purchases can be made at open market prices or in private transactions and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. On March 21, 2011, the Board of Directors authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock (the "2011 Plan"). No shares of common stock were repurchased during the twelve months ended December 31, 2015 under the 2011 Plan. The table below provides the amount of the fourth quarter issuer purchases of equity securities.
Period
 
Total
Number
of Shares
Purchased (a)
 
Average Price
Paid per Share
(Including
Commissions)
 
Total Number of
Shares Purchased as
Part of a Publicly
Announced Program
 
Maximum Number of Shares that May Yet Be Purchased
Under the Plans
or Programs
October 1 to October 31, 2015
 

 
$

 

 
393,816
November 1 to November 30, 2015
 

 

 

 
393,816
December 1 to December 31, 2015
 
12,313

 
37.42

 

 
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.

22


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


23


Item 6. Selected Financial Data

As of and for the following periods (in thousands except for share and per share data):
 
 
Years Ended December 31,
 
2015
 
2014
 
2013
 
2012
 
2011
Operating revenues
$
849,869

 
$
917,525

 
$
890,362

 
$
852,881

 
$
918,013

Operating income
146,191

 
$
151,163

 
$
165,635

 
$
168,658

 
$
190,803

Net income
$
81,918

 
$
91,428

 
$
88,583

 
$
90,846

 
$
103,539

Basic earnings per share:
 
 
 
 
 
 
 
 
 
Net income
$
2.03

 
$
2.27

 
$
2.20

 
$
2.27

 
$
2.49

Weighted average number of shares outstanding
40,274,986

 
40,190,991

 
40,114,594

 
39,974,022

 
41,349,883

Diluted earnings per share:
 
 
 
 
 
 
 
 
 
Net income
$
2.03

 
$
2.27

 
$
2.20

 
$
2.26

 
$
2.48

Weighted average number of shares and dilutive
 
 
 
 
 
 
 
 
 
 potential shares outstanding
40,308,562

 
40,211,717

 
40,126,647

 
40,055,581

 
41,587,059

Dividends declared per share of common stock
$
1.165

 
$
1.105

 
$
1.045

 
$
0.97

 
$
0.66

Cash additions to utility property, plant and equipment
$
281,458

 
$
277,078

 
$
237,411

 
$
202,387

 
$
178,041

Total assets
$
3,233,852

 
$
3,059,301

 
$
2,786,288

 
$
2,669,050

 
$
2,396,851

Long-term debt, net of current portion
$
1,134,284

 
$
1,134,179

 
$
999,620

 
$
999,535

 
$
816,497

Common stock equity
$
1,016,538

 
$
984,254

 
$
943,833

 
$
824,999

 
$
760,251




24


Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations

As you read this Management’s Discussion and Analysis, please refer to our Financial Statements and the accompanying notes, which contain our operating results.
Summary of Critical Accounting Policies and Estimates
Our financial statements have been prepared in conformity with Generally Accepted Accounting Principles ("GAAP"). Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to Financial Statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and ARO. Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operation.
Regulatory Accounting
We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of December 31, 2015, we had recorded regulatory assets currently subject to recovery in future rates of approximately $115.1 million and regulatory liabilities of approximately $24.3 million as discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements. Included in regulatory assets are regulatory tax assets of approximately $69.4 million primarily related to the regulatory treatment of the equity portion of allowance for funds used during construction ("AFUDC") and state deferred income taxes.
In the event we determine that we can no longer apply the Financial Accounting Standards Board (the "FASB") guidance for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, based on regulatory action, we could be required to record a charge against income in the amount of the unamortized balance of the related regulatory assets. Such an action could materially reduce our total assets, specifically our total deferred charges and other assets, and shareholders' equity.
Collection of Fuel Expense
In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT on a periodic basis every one to three years. The NMPRC, in its discretion, may order that a prudence review be conducted to assure that fuel and purchased power costs recovered from customers are prudently incurred. Prior to the completion of a reconciliation proceeding or audit, we record fuel transactions such that fuel revenues, including fuel costs recovered through base rates in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation proceeding or an audit, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.
The Company’s Texas fuel and purchased power costs through March 31, 2013 were reconciled in PUCT Docket No. 41852. As of December 31, 2015, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $413.8 million. The Company is required to file an application in 2016 for fuel reconciliation of the Company's fuel expenses in its Texas jurisdiction for the period through March 31, 2016. The NMPRC approved the continuation of its use of the Fuel and Purchase Power Cost Adjustment Clause without modification and the Company’s application requesting reconciliation of fuel and purchased power costs through December 2012 in Case No. 13-00380-UT. New Mexico jurisdictional costs subject to prudence review are for costs from January 2013 through December 31, 2015 and are approximately $194.4 million.
The Company recovers fuel and purchased power costs from the RGEC pursuant to an ongoing contract with a two-year notice to terminate provision. The contract includes a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC and is updated on an annual basis. This update is reviewed and approved by the RGEC annually in February following the prior calendar year. As of December 31, 2015, the RGEC fuel costs subject to review are approximately $1.4 million.

25


Decommissioning Costs and Estimated Asset Retirement Obligation
Pursuant to the ANPP Participation Agreement, the rules and regulations of the Nuclear Regulatory Commission and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The determination of the estimated liability is based on site-specific estimates, which are updated every three years and involve numerous judgments and assumptions, including estimates of future decommissioning costs at current price levels, escalation rates and discount rates. The Palo Verde ARO is approximately $72.8 million and represents approximately 89% of our total ARO balance of $81.6 million at December 31, 2015. A 10% increase in the estimates of future Palo Verde decommissioning costs at current price levels would have increased the ARO liability by $6.0 million at December 31, 2015.
We are required to fund estimated nuclear decommissioning costs over the life of the generating facilities through the use of external trust funds pursuant to rules of the Nuclear Regulatory Commission and PUCT and the ANPP Participation Agreement. Historically, we have been permitted to collect in rates in Texas and New Mexico the funding requirements for our nuclear decommissioning trusts, except for a portion of Palo Verde Unit 3, which is deregulated in the New Mexico jurisdiction. While we attempt to seek amounts in rates to meet decommissioning obligations, we are not able to conclude given the evidence available to us now that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. We are ultimately responsible for these costs and our future actions combined with future decisions from regulators will determine how successful we are in this effort.     
The funding amounts are based on assumptions about future investment returns and future decommissioning cost escalations. If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the nuclear plant increase, we could be required to increase our funding to the nuclear decommissioning trusts.
Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $113.3 million as of December 31, 2015. A hypothetical 10% increase in interest rates would have reduced the fair values of these funds by $1.2 million at December 31, 2015. Our decommissioning trust funds also include marketable equity securities of approximately $117.5 million at December 31, 2015. A hypothetical 20% decrease in equity prices would have reduced the fair values of these funds by $23.5 million at December 31, 2015. Declines in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements.
We do not anticipate expending monies held in the nuclear decommissioning trusts before 2044 or a later period when decommissioning of Palo Verde begins.
Future Pension and Other Post-retirement Obligations
We maintain a qualified noncontributory defined benefit pension plan, which covers substantially all of our employees, and two non-funded nonqualified supplement plans that provide benefits in excess of amounts permitted under the provisions of the tax law for certain participants in the qualified plan. We also sponsor a plan that provides other post-retirement benefits, such as health and life insurance benefits to retired employees. Our net obligations under these various benefit plans at December 31, 2015 totaled $147.2 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled $11.0 million for the twelve months ended December 31, 2015.
Our pension and other post-retirement benefit liabilities and the related net periodic benefit costs are calculated on the basis of a number of actuarial assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. For 2015, the discount rates used to measure our year end liabilities are based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. As of December 31, 2015, the corresponding weighted-average discount rates range from 3.99% to 4.59% depending upon the benefit plan.
Our overall expected long-term rate of return on assets for the pension trust fund is 7.0% effective January 1, 2016, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. Our overall expected long-term rate of return on assets for the other post-retirement benefits trust, on an after-tax basis, is 4.875% effective January 1, 2016. Both expected long-term rates of return are based on the after-tax weighted average of the expected returns on investments. The expected returns on investments in the pension trust and the other post-retirement benefits trust are based upon the target asset allocations for the two trusts.
Our accrued post-retirement benefit liability and the service and interest components of the related net periodic benefit costs are calculated using an actuarial assumption regarding health care cost inflation. For measurement purposes, a 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan.

26


The estimated rate of compensation increase used in our Retirement Plans is 4.5% and is based on recent trends for all non-union employees and the amounts we are contractually obligated for union employees.
In fiscal 2016, we expect to change the method used to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits. This change compared to the previous method will result in a decrease in the service and interest components in future periods. Historically, we estimated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2016, we have elected to utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. We believe the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding spot rates on the yield curve. We will account for this change as a change in accounting estimate and accordingly will account for this prospectively. The change in estimate is anticipated to decrease the service and interest components of net period benefit cost for pension and other post-retirement benefits by $2.9 million and $0.9 million, respectively, starting in 2016.
The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2015 reported pension liability and our 2015 reported pension expense (in thousands):
 
 
Increase (Decrease)
Actuarial Assumption
 
Impact on Pension Liability
 
Impact on Pension Expense
Discount rate:
 
 
 
 
Increase 1%
 
$
(40,115
)
 
$
(3,779
)
Decrease 1%
 
49,216

 
4,574

Expected long-term rate of return on plan assets:
 
 
 
 
Increase 1%
 
N/A

 
2,633

Decrease 1%
 
N/A

 
(2,633
)
Compensation rate:
 
 
 
 
Increase 1%
 
6,188

 
1,470

Decrease 1%
 
(5,640
)
 
(1,316
)
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2015 other postretirement benefit obligations and our 2015 reported other postretirement benefit expense (in thousands):
 
 
Increase (Decrease)
Actuarial Assumption
 
Impact on Other Post-retirement Benefit Obligation
 
Impact on Other Post-retirement Benefit Expense
 
Impact on Other Post-retirement Service and Interest Cost
Discount rate:
 
 
 
 
 
 
Increase 1%
 
$
(11,754
)
 
$
(1,750
)
 
$
(423
)
Decrease 1%
 
14,528

 
2,208

 
526

Healthcare cost trend rate:
 
 
 
 
 
 
Increase 1%
 
13,006

 
3,041

 
1,571

Decrease 1%
 
(11,718
)
 
(2,396
)
 
(1,211
)
Expected long-term rate of return on plan assets:
 
 
 
 
 
 
Increase 1%
 
N/A

 
(398
)
 
N/A

Decrease 1%
 
N/A

 
398

 
N/A




27


Tax Accruals
We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation or audit adjustments can materially affect amounts we recognize in our financial statements.
When appropriate, we record a valuation allowance against deferred tax assets to reflect that these tax assets may not be realized. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the results of operations and financial position of the Company. There were no valuation allowances for deferred tax assets at December 31, 2015.
We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. The unrecognized tax benefits that do not meet the recognition and measurement standards are $3.6 million at December 31, 2015.

Overview
The following is an overview of our results of operations for the years ended December 31, 2015, 2014 and 2013. Net income and basic earnings per share for the years ended December 31, 2015, 2014 and 2013 are shown below:
 
 
Years Ended December 31,
 
2015
 
2014
 
2013
Net income (in thousands)
$
81,918

 
$
91,428

 
$
88,583

Basic earnings per share
2.03

 
2.27

 
2.20

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


28


The following table and accompanying explanations show the primary factors affecting the after-tax change in income between the calendar years ended 2015 and 2014, 2014 and 2013, and 2013 and 2012 (in thousands):
 

2015
 
2014
 
2013
 
Prior year December 31 net income
$
91,428

  
$
88,583

  
$
90,846

  
Change in (net of tax):
 
 
 
 
 
 
Increased (decreased) non-base revenue, net of energy expense
(5,370
)
(a)
3,779

(b)
2,345

(c)
Increased (decreased) allowance for funds used during construction
(4,953
)
(d)
6,157

(e)
895

 
Increased interest on long-term debt (net of capitalized interest)
(4,516
)
(f)
(390
)
 
(2,611
)
(g)
Increased depreciation and amortization
(4,214
)
(h)
(2,415
)
(i)
(696
)
 
(Increased) decreased administrative and general expense
(1,653
)
(j)
1,536

(k)
(2,011
)
(l)
Increased taxes other than income taxes
(641
)
 
(3,252
)
(m)
(198
)
 
Decreased (increased) operation and maintenance at fossil-fuel generating plants
(294
)
 
(1,792
)
(n)
751

 
Increased (decreased) retail non-fuel base revenues
9,290

(o)
(3,533
)
(p)
(2,459
)
(q)
Increased (decrease) investment and interest income
3,084

(r)
5,309

(s)
1,382

(s)
Decreased (increased) Palo Verde operations and maintenance expense
1,030

 
(1,635
)
(t)
964

 
Other
(1,273
)
 
(919
)
 
(625
)
 
Current year December 31 net income
$
81,918

  
$
91,428

  
$
88,583

  
______________________ 
Footnotes reflect pre-tax amounts
(a)
Non-base revenues, net of energy expenses decreased due to: (i) a decrease of $5.3 million in deregulated Palo Verde Unit 3 revenues; (ii) the recognition in 2014 of Palo Verde performance rewards of $2.2 million associated with the 2009 to 2012 performance periods, net of disallowed fuel and purchased power costs related to the resolution for the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852; and (iii) a decrease of $0.7 million in energy efficiency bonuses awarded. These decreases were partially offset by an increase of $1.7 million in transmission wheeling revenues.
(b)
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.
(c)
Non-base revenues, net of energy expenses increased due to an increase of $1.6 million in deregulated Palo Verde Unit 3 revenues and an increase of $0.5 million in off-system sales retained margins.
(d)
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.
(e)
AFUDC increased, primarily due to higher balances of construction work in progress subject to AFUDC, primarily reflecting construction work in progress on MPS and the EOC.
(f)
Interest on long-term debt increased, primarily due to interest on $150 million of 5.00% Senior Notes issued in December 2014.
(g)
Interest on long-term debt increased, primarily due to interest on $150 million of 3.3% Senior Notes issued in December 2012, partially offset by the refunding and remarketing of two series of pollution control bonds at lower rates in August 2012.
(h)
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.
(i)
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.

29


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





30


Historical Results of Operations
The following discussion includes detailed descriptions of factors affecting individual line items in the results of operations. The amounts presented below are presented on a pre-tax basis.
Operating revenues
We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale power market generally at market-based prices. Sales for resale, which are FERC-regulated cost-based wholesale sales within our service territory, accounted for less than 1% of revenues in each of 2015, 2014 and 2013.
Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment mechanisms. A significant portion of fuel costs are also recovered through base rates in New Mexico. We record deferred fuel revenues for the difference between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. "Non-fuel base revenues" refers to our revenues from the sale of electricity excluding such fuel costs.
Retail non-fuel base revenue percentages by customer class are presented below:
 
    
 
Years Ended December 31,
 
2015
 
2014
 
2013
Residential
44
%
 
42
%
 
43
%
Commercial and industrial, small
33

 
34

 
33

Commercial and industrial, large
7

 
7

 
7

Sales to public authorities
16

 
17

 
17

Total retail non-fuel base revenues
100
%
 
100
%
 
100
%
No retail customer accounted for more than 4% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers comprise 77% of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structures in New Mexico and Texas reflect higher base rates during the peak summer season of May through October and lower base rates during November through April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base revenues derived during each quarter for the periods presented:
 
        
 
Years Ended December 31,
 
2015
 
2014
 
2013
January 1 to March 31
18
%
 
19
%
 
20
%
April 1 to June 30
26

 
27

 
27

July 1 to September 30
35

 
33

 
33

October 1 to December 31
21

 
21

 
20

Total
100
%
 
100
%
 
100
%
Weather significantly impacts our residential, small commercial and industrial customers, and to a lesser extent, our sales to public authorities. Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree the average outdoor temperature varies from a standard of 65 degrees Fahrenheit, a degree day is recorded. The table below shows heating and cooling degree days compared to a 10-year average for 2015, 2014 and 2013. 

        
 
2015
 
2014
 
2013
 
10-year
Average
Cooling degree days
2,839

 
2,671

 
2,695

 
2,696

Heating degree days
2,095

 
1,900

 
2,426

 
2,174



31


Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.4% and 1.3% in 2015 and 2014, respectively. See the tables presented on pages 34 and 35 which provide detail on the average number of retail customers and the related revenues and kWh sales.
Retail non-fuel base revenues. Retail non-fuel base revenues increased $14.3 million, or 2.6%, for the twelve months ended December 31, 2015 when compared to the twelve months ended December 31, 2014. This increase includes an $11.9 million increase in revenues from residential customers and a $2.0 million increase in revenues from small commercial and industrial customers reflecting hotter summer weather and increases of 1.3% and 1.6%, respectively, in the average number of residential customers and small commercial and industrial customers. KWh sales to public authorities increased 1.5% while revenue declined by $0.8 million primarily due to a military installation moving a portion of their load to an interruptible rate. Retail non-fuel revenues from large commercial and industrial customers increased $1.2 million due to an interruptible rate adjustment for a large customer. Cooling degree days increased 6.3% in 2015, when compared to the same period last year, and were 5.3% over the 10-year average. Heating degree days increased 10.3% for 2015, compared to 2014, and were 3.6% below the 10-year average.
Retail non-fuel base revenues decreased by $5.4 million, or 1.0%, for the twelve months ended December 31, 2014 when compared to the twelve months ended December 31, 2013. The decrease reflects a $3.0 million decrease from sales to public authorities, primarily due to an increased use of an interruptible rate by a military installation customer, as well as other energy savings from energy conservation and efficiency programs and use of solar distributed generation at military installations. The decrease in retail non-fuel base revenues also resulted from a decline in sales to residential customers of $2.3 million and reflects milder weather in 2014, primarily in the first quarter. The milder weather also suppressed sales to small commercial and industrial customers, and to a lesser extent public authority customers. Heating degree days decreased 21.7% when compared to 2013, and were 12.9% below the 10-year average. Cooling degree days were relatively consistent with both 2013 and the 10-year average. KWh sales to residential customers decreased 1.4% while the average number of residential customers served increased 1.3%. Retail non-fuel base revenues from sales to small commercial and industrial customers increased slightly, when compared to 2013, due to a 2.0% increase in the average number of customers served partially offset by milder weather. KWh sales to, and retail non-fuel base revenues from, large commercial and industrial customers decreased 2.8% and 2.5%, respectively, as several customers terminated operations.
Fuel revenues. Fuel revenues consist of (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions and the FERC, (ii) deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers, and (iii) fuel costs recovered in base rates in New Mexico. In New Mexico and with our sales for resale customer, the fuel adjustment clause allows us to recover under-recoveries or refund over-recoveries of current fuel costs above the amount recovered in base rates with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor based upon an approved formula at least four months after our last revision, except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over and under recoveries are defined as material when they exceed 4% of the previous twelve months' fuel costs.
We over-recovered fuel costs by $13.3 million in the twelve months ended December 31, 2015. We under-recovered fuel costs by $3.1 million and $10.8 million in the twelve months ended December 31, 2014 and 2013, respectively. In May 2014, we implemented a 6.9% increase in our fixed fuel factor in Texas, which was based upon a formula that reflects increases in prices for natural gas. On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015. In July 2014, the PUCT approved a settlement in the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852 and financial implications of the settlement were recorded in the second quarter of 2014 increasing fuel revenues by $2.2 million. In September 2014 and March 2015, $7.9 million and $5.8 million, respectively, were credited to customers through the applicable fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage. At December 31, 2015, we had a net fuel over-recovery balance of $4.0 million, including an over-recovery balance $0.1 million in Texas, $3.8 million in New Mexico and $0.1 million in the FERC jurisdiction.
Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. We have shared 100% of margins on non-arbitrage sales (as defined by the settlement) and 50% of margins on arbitrage sales with our Texas customers since April 1, 2014. For the period from April 1, 2014 through June 30, 2015, our total share of margins assignable to the Texas retail jurisdiction, on arbitrage and non-arbitrage off-system sales, may not exceed 10% of the total margins assignable to the Texas retail jurisdiction on all off-system sales. Prior to April 1, 2014, we shared 90% of off-system sales margins with our Texas customers, and we retained 10% of off-system sales margins. We are currently sharing 90% of off-system sales margins with our New Mexico customers, and 25% of our off-system sales margins with our sales for resale customer under the terms of their contract.

32


Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. Palo Verde's availability is an important factor in realizing these off-system sales margins.
The table below shows MWhs, sales revenue, fuel cost, total margins, and retained margins made on off-system sales for the twelve months ended December 31, 2015, 2014 and 2013 (in thousands except for MWhs).

        
 
Years Ended December 31,
 
2015
 
2014
 
2013
MWh sales
2,500,947

 
2,609,769

 
2,472,622

Sales revenue
$
64,816

 
$
97,980

 
$
82,806

Fuel cost
$
52,406

 
$
74,716

 
$
68,241

Total margins
$
12,410

 
$
23,264

 
$
14,565

Retained margins
$
1,362

 
$
2,147

 
$
1,549


Off-system sales revenues decreased $33.2 million, or 33.8%, and the related retained margins decreased $0.8 million, or 36.6%, for the twelve months ended December 31, 2015 when compared to 2014 as a result of lower average market prices for power and a 4.2% decrease in MWh sales. Off-system sales revenues increased $15.2 million, or 18.3%, and the related retained margins increased $0.6 million, or 38.6%, for the twelve months ended December 31, 2014 when compared to 2013 as a result of higher average market prices for power and a 5.5% increase in MWh sales.
 


33


Comparisons of kWh sales and operating revenues are shown below: 
 
 
 
 
 
Increase (Decrease)
 
 
Years Ended December 31:
2015
 
2014
 
Amount
 
Percent
 
 
kWh sales (in thousands):
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
Residential
2,771,138

 
2,640,535

 
130,603

 
4.9
 %
 
 
Commercial and industrial, small
2,384,514

 
2,357,846

 
26,668

 
1.1

 
 
Commercial and industrial, large
1,062,662

 
1,064,475

 
(1,813
)
 
(0.2
)
 
 
Sales to public authorities
1,585,568

 
1,562,784

 
22,784

 
1.5

 
 
Total retail sales
7,803,882

 
7,625,640

 
178,242

 
2.3

 
 
Wholesale:
 
 
 
 
 
 


 
 
Sales for resale
63,347

 
61,729

 
1,618

 
2.6

 
 
Off-system sales
2,500,947

 
2,609,769

 
(108,822
)
 
(4.2
)
 
 
Total wholesale sales
2,564,294

 
2,671,498

 
(107,204
)
 
(4.0
)
 
 
Total kWh sales
10,368,176

 
10,297,138

 
71,038

 
0.7

 
 
Operating revenues (in thousands):
 
 
 
 
 
 


 
 
Non-fuel base revenues:
 
 
 
 
 
 


 
 
Retail:
 
 
 
 
 
 


 
 
Residential
$
246,265

 
$
234,371

 
$
11,894

 
5.1
 %
 
 
Commercial and industrial, small
187,436

 
185,388

 
2,048

 
1.1

 
 
Commercial and industrial, large
40,411

 
39,239

 
1,172

 
3.0

 
 
Sales to public authorities
91,244

 
92,066

 
(822
)
 
(0.9
)
 
 
Total retail non-fuel base revenues
565,356

 
551,064

 
14,292

 
2.6

 
 
Wholesale:
 
 
 
 
 
 


 
 
Sales for resale
2,455

 
2,277

 
178

 
7.8

 
 
Total non-fuel base revenues
567,811

 
553,341

 
14,470

 
2.6

 
 
Fuel revenues:
 
 
 
 
 
 


 
 
Recovered from customers during the period
127,765

 
161,052

 
(33,287
)
 
(20.7
)
 
 
Under (over) collection of fuel (1)
(13,342
)
 
3,110

 
(16,452
)
 
-

 
 
New Mexico fuel in base rates
72,129

 
71,614

 
515

 
0.7

 
 
Total fuel revenues (2)
186,552

 
235,776

 
(49,224
)
 
(20.9
)
 
 
Off-system sales:
 
 
 
 
 
 


 
 
Fuel cost
52,406

 
74,716

 
(22,310
)
 
(29.9
)
 
 
Shared margins
11,048

 
21,117

 
(10,069
)
 
(47.7
)
 
 
Retained margins
1,362

 
2,147

 
(785
)
 
(36.6
)
 
 
Total off-system sales
64,816

 
97,980

 
(33,164
)
 
(33.8
)
 
 
 
 
 
 
 
 
 


 
 
Other (3) (4)
30,690

 
30,428

 
262

 
0.9

 
 
Total operating revenues
$
849,869

 
$
917,525

 
$
(67,656
)
 
(7.4
)
 
  
Average number of retail customers (5):
 
 
 
 
 
 


 
 
Residential
356,969

 
352,277

 
4,692

 
1.3
 %
 
  
Commercial and industrial, small
40,250

 
39,600

 
650

 
1.6

 
  
Commercial and industrial, large
49

 
49

 

 
-

 
  
Sales to public authorities
5,250

 
5,088

 
162

 
3.2

 
 
Total
402,518

 
397,014

 
5,504

 
1.4

 
  
 ___________________________
(1)
Includes the portion of DOE refunds related to spent fuel storage of $5.8 million and $7.9 million in 2015 and 2014, respectively, that were credited to customers through the applicable fuel adjustment clauses. 2014 includes $2.2 million related to Palo Verde performance rewards, net.
(2)
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.7 million and $15.0 million in 2015 and 2014, respectively. 
(3)
Includes an Energy Efficiency Bonus of $1.3 million and $2.0 million in 2015 and 2014, respectively. 
(4)
Represents revenues with no related kWh sales.
(5)
The number of retail customers presented is based on the number of service locations.

34


 
 
 
 
 
Increase (Decrease)
 
 
Years Ended December 31:
2014
 
2013
 
Amount
 
Percent
 
 
kWh sales (in thousands):
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
Residential
2,640,535

 
2,679,262

 
(38,727
)
 
(1.4
)%
 
 
Commercial and industrial, small
2,357,846

 
2,349,148

 
8,698

 
0.4

 
 
Commercial and industrial, large
1,064,475

 
1,095,379

 
(30,904
)
 
(2.8
)
 
 
Sales to public authorities
1,562,784

 
1,622,607

 
(59,823
)
 
(3.7
)
 
 
Total retail sales
7,625,640

 
7,746,396

 
(120,756
)
 
(1.6
)
 
 
Wholesale:
 
 
 
 
 
 


 
 
Sales for resale
61,729

 
61,232

 
497

 
0.8

 
 
Off-system sales
2,609,769

 
2,472,622

 
137,147

 
5.5

 
 
Total wholesale sales
2,671,498

 
2,533,854

 
137,644

 
5.4

 
 
Total kWh sales
10,297,138

 
10,280,250

 
16,888

 
0.2

 
 
Operating revenues (in thousands):
 
 
 
 
 
 


 
 
Non-fuel base revenues:
 
 
 
 
 
 


 
 
Retail:
 
 
 
 
 
 


 
 
Residential
$
234,371

 
$
236,651

 
$
(2,280
)
 
(1.0
)%
 
 
Commercial and industrial, small
185,388

 
184,568

 
820

 
0.4

 
 
Commercial and industrial, large
39,239

 
40,235

 
(996
)
 
(2.5
)
 
 
Sales to public authorities
92,066

 
95,044

 
(2,978
)
 
(3.1
)
 
 
Total retail non-fuel base revenues
551,064

 
556,498

 
(5,434
)
 
(1.0
)
 
 
Wholesale:
 
 
 
 
 
 


 
 
Sales for resale
2,277

 
2,172

 
105

 
4.8

 
 
Total non-fuel base revenues
553,341

 
558,670

 
(5,329
)
 
(1.0
)
 
 
Fuel revenues:
 
 
 
 
 
 


 
 
Recovered from customers during the period
161,052

 
133,481

 
27,571

 
20.7

 
 
Under collection of fuel (1)
3,110

 
10,849

 
(7,739
)
 
(71.3
)
 
 
New Mexico fuel in base rates
71,614

 
73,295

 
(1,681
)
 
(2.3
)
 
 
Total fuel revenues (2)
235,776

 
217,625

 
18,151

 
8.3

 
 
Off-system sales:
 
 
 
 
 
 


 
 
Fuel cost
74,716

 
68,241

 
6,475

 
9.5

 
 
Shared margins
21,117

 
13,016

 
8,101

 
62.2

 
 
Retained margins
2,147

 
1,549

 
598

 
38.6

 
 
Total off-system sales
97,980

 
82,806

 
15,174

 
18.3

 
 
 
 
 
 
 
 
 


 
 
Other (3) (4)
30,428

 
31,261

 
(833
)
 
(2.7
)
 
 
Total operating revenues
$
917,525

 
$
890,362

 
$
27,163

 
3.1

 
  
Average number of retail customers (5):
 
 
 
 
 
 


 
 
Residential
352,277

 
347,891

 
4,386

 
1.3
 %
 
  
Commercial and industrial, small
39,600

 
38,836

 
764

 
2.0

 
  
Commercial and industrial, large
49

 
50

 
(1
)
 
(2.0
)
 
  
Sales to public authorities
5,088

 
4,997

 
91

 
1.8

 
 
Total
397,014

 
391,774

 
5,240

 
1.3

 
  
 _______________________
(1)
2014 includes a DOE refund related to spent fuel storage of $7.9 million offset in part by $2.2 million related to Palo Verde performance rewards, net.
(2)
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $15.0 million and $11.4 million in 2014 and 2013, respectively.
(3)
Includes an Energy Efficiency Bonus of $2.0 million and $0.5 million in 2014 and 2013, respectively. 
(4)
Represents revenues with no related kWh sales.
(5)
The number of retail customers presented is based on the number of service locations.

35


Energy expenses
Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. Palo Verde represents approximately 31% of our available net generating capacity and approximately 54% of our Company-generated energy for the twelve months ended December 31, 2015. Fluctuations in the price of natural gas, which is also the primary factor influencing the price of purchased power, have had a significant impact on our cost of energy.
Energy expenses decreased $73.9 million, or 23.4%, for the twelve months ended December 31, 2015 compared to 2014, primarily due to (i) decreased natural gas costs of $62.5 million due to a 32.0% decrease in the average price of natural gas, (ii) decreased total purchased power of $11.3 million due to a 18.7% decrease in the average price of total purchased power, and (iii) decreased nuclear fuel expense of $1.2 million due to a 7.2% decrease in the cost of nuclear fuel consumed. The decrease in energy expense was partially offset by (i) a $2.1 million reduction in the 2015 DOE refund compared to 2014, and (ii) an increase in coal costs of $1.0 million due to a 10.3% increase in the MWhs generated with coal.
Energy expenses increased $26.7 million, or 9.2%, for the twelve months ended December 31, 2014 compared to 2013, primarily due to (i) increased natural gas costs of $32.7 million due to a 17.1% increase in the average costs of natural gas and a 2.4% increase in MWhs generated with natural gas, and (ii) increased total purchased power of $2.4 million due to a 17.5% increase in the average price of total purchased power partially offset by a 10.2% decrease in MWhs purchased. Photovoltaic purchased power costs per MWh decreased for the twelve months ended December 31, 2014, when compared to the same period in 2013 primarily due to the lower priced purchases from Macho Springs solar photovoltaic project which began commercial operation in May 2014. The increase in energy expense was partially offset by a decrease in nuclear fuel expense related to an $8.5 million settlement with the DOE for reimbursement of spent fuel storage and management costs recorded in 2014.
The table below details the sources and costs of energy for 2015, 2014 and 2013. 
 
2015
 
2014
Fuel Type
Cost
 
MWh
 
Cost per
MWh
 
Cost
 
MWh
 
Cost per
MWh
 
(in thousands)
 
 
 
 
 
(in thousands)
 
 
 
 
Natural Gas
$
134,361

 
3,790,659

 
$
35.45

 
$
196,833

 
3,774,209

 
$
52.15

Coal
13,913

 
657,744