Annual Report


 
 
 
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, 2016
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, 2016 , the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,883,999,218 (based on the closing price as quoted on the New York Stock Exchange on that date).
As of January 31, 2017 , there were 40,557,679 shares of the Company’s no par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for the 2017 annual meeting of its shareholders are incorporated by reference into Part III of this report.

 
 
 

Table of Contents

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
GHG
 
Greenhouse gas
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
 


               
 
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Table of Contents

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

 


               
 
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Table of Contents

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

               
 
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Table of Contents

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


               
 
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Table of Contents

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 2,080 MW. For the year ended December 31, 2016, the Company’s energy sources consisted of approximately 49% nuclear fuel, 34% natural gas, 2% coal, 15% purchased power and less than 1% generated by Company-owned solar photovoltaic panels. The Company continues to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. As of December 31, 2016, the Company had power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources – Purchased Power").
The Company serves approximately 411,100 residential, commercial, industrial, public authority and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 64% and 11%, respectively, of the Company’s retail revenues for the year ended December 31, 2016). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public authority and other large retail customers of the Company include United States military installations, such as Fort Bliss in Texas and White Sands Missile Range ("White Sands") and Holloman Air Force Base ("HAFB") in New Mexico, an oil refinery, several medical centers, two large universities and a steel production facility.
The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone: 915-543-5711). The Company was incorporated in Texas in 1901. As of January 31, 2017, the Company had approximately 1,100 employees, 38% of whom are covered by a collective bargaining agreement.
The Company makes available free of charge through its website, www.epelectric.com , its Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statement and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission ("SEC"). In addition, copies of this Annual Report on Form 10-K will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov . The information on the Company's website is not incorporated by reference into this Annual Report on Form 10-K.
Facilities
As of December 31, 2016, the Company’s net dependable generating capability of approximately 2,080 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
%
El Paso, Texas
Palo Verde
 
Nuclear
 
633

15.8
%
Wintersburg, Arizona
Rio Grande Power Station
 
Natural Gas
 
276

100
%
Sunland Park, New Mexico
Montana Power Station (Units 1, 2, 3 and 4)
 
Natural Gas
 
354

100
%
El Paso, Texas
Copper Power Station
 
Natural Gas
 
64

100
%
El Paso, Texas
Renewables
 
Solar
 
1

100
%
Culberson/El Paso Counties, Texas; Dona Ana County, New Mexico
Total
 
 
 
2,080

 
 
 





1



Palo Verde
The Company owns an interest, along with six other utilities, in the three nuclear generating units and common facilities ("Common Facilities") at Palo Verde. Arizona Public Service Company ("APS") serves as operating agent for Palo Verde, and under the Arizona Nuclear Power Project Participation Agreement ("ANPP Participation Agreement"), the Company has limited ability to influence operations and costs at Palo Verde.
Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the Nuclear Regulatory Commission ("NRC"). The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 2047, respectively.
Decommissioning . Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses. In 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013 Study"), which estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs. At December 31, 2016 , the Company's decommissioning trust fund had a balance of $255.7 million . Although the 2013 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates attributable to the Company will not increase in the future or that regulatory requirements will not change. A 2016 Palo Verde decommissioning study is underway and is expected to be finalized in the second quarter of 2017 at which time the Company will record its effects.
Spent Fuel Storage . Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the United States Department of Energy ("DOE") is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On August 18, 2014, APS and the DOE entered into a settlement agreement stipulating to a dismissal of the lawsuit and payment of $57.4 million by the DOE to the Palo Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received approximately $9.1 million , representing its share of the award, of which $7.9 million was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS, acting on behalf of itself and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was $42.0 million . On June 1, 2015, the Company received approximately $6.6 million , representing its share of the award, of which $5.8 million was credited to customers through the applicable fuel adjustment clauses in March 2015. After June 2015, APS will file annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. Funds related to this claim were received in the first quarter of 2016. The Company's share of this claim is approximately $1.9 million , of which $1.6 million was credited to customers through the applicable fuel adjustment clauses in March 2016 . On October 31, 2016 APS filed an $11.3 million claim for the period July 1, 2015 through June 30, 2016. The Company's share of this claim is approximately $1.8 million . On February 1, 2017, the DOE notified APS of the approval of the claim. Any reimbursement is anticipated to be received in the second quarter of 2017, and the majority of the award received by the Company will be credited to customers through applicable fuel adjustment clauses.
DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations by designing, licensing, constructing and operating a permanent geologic repository in Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE's authority to withdraw the Yucca Mountain construction authorization

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application and NRC’s cessation of its review of the Yucca Mountain construction authorization application. The cases have been consolidated into one matter at the U.S. Court of Appeals for the District of Columbia Circuit (the "D.C. Circuit"). In August 2013, the D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds.
On October 16, 2014, the NRC issued Volume 3 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume addresses repository safety after permanent closure, and the issuance of Volume 3 is a key milestone in the Yucca Mountain licensing process. Volume 3 contains the NRC staff’s finding that the DOE’s repository design meets the requirements that apply after the repository is permanently closed, including but not limited to the post-closure performance objectives in the NRC’s regulations.
On December 18, 2014, the NRC issued Volume 4 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume covers administrative and programmatic requirements for the repository. It documents the NRC staff’s evaluation of whether the DOE’s research and development and performance confirmation programs, as well as other administrative controls and systems, meet applicable NRC requirements. Volume 4 contains the NRC staff’s finding that most administrative and programmatic requirements in NRC regulations are met, except for certain requirements relating to ownership of land and water rights.
Publication of Volumes 3 and 4 does not signal whether or when the NRC might authorize construction of the repository. The Company cannot predict when spent fuel shipments to the DOE will commence.
Waste Confidence. On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule ("Waste Confidence Decision").
The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which, consistent with the National Environmental Policy Act ("NEPA"), requires either an environmental impact statement or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action consistent with NEPA.
On September 6, 2012, the NRC Commissioners issued a directive to the NRC staff to proceed directly with development of a generic environmental impact statement to support an updated Waste Confidence Decision. The NRC Commissioners also directed the NRC staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.
In September 2013, the NRC issued its draft Generic Environmental Impact Statement ("GEIS") to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. The continued storage rule adopted the findings of the GEIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although Palo Verde has not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The final Continued Storage Rule was subject to continuing legal challenges before the NRC and the Court of Appeals. In June 2016, the D.C. Circuit issued its final decision, rejecting all remaining legal challenges to the Continue Storage Rule. On August 8, 2016, the D.C. Circuit denied a petition for rehearing.
Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation ("ISFSI") to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.
The One-Mill Fee. In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged the DOE’s 2010 determination of the adequacy of the one tenth of a cent per kWh

3


fee (the "one-mill fee") paid by the nation’s commercial nuclear power plant owners pursuant to their individual obligations under the Standard Contract. This fee was recovered by the Company through applicable fuel adjustment clauses. In June 2012, the D.C. Circuit held that the DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the Secretary of the DOE (the "Secretary") with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of the DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the Secretary to notify Congress of his intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators, as he is required to do pursuant to the NWPA and the court’s order. On January 3, 2014, the Secretary notified Congress of his intention to suspend collection of the one-mill fee, subject to Congress’ disapproval and on May 12, 2014, APS was notified by the DOE that, effective May 16, 2014, the one-mill fee would be suspended. Electricity generated at Palo Verde and sold prior to May 16, 2014 remained subject to the one-mill fee.
NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan . The NRC regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee's safety performance. Following the March 11, 2011 earthquake and tsunami in Japan, the NRC established a task force to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system. On March 12, 2012, the NRC issued the first regulatory requirements based on the recommendations of the NRC's Near Term Task Force. With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants and (2) enhancement of spent fuel pool instrumentation.
The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Palo Verde has met the NRC's imposed deadlines for the installation of equipment to address these requirements. Palo Verde has spent approximately $125.0 million (the Company's share is $19.7 million ) on capital enhancements related to these requirements as of December 31, 2016.
Liability and Insurance Matters . The Palo Verde Participants have insurance for public liability resulting from nuclear energy hazards, covered by primary liability insurance provided by commercial insurance carriers and an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis up to $60.4 million , with an annual payment limitation of approximately $9.0 million . The Palo Verde Participants also maintain $2.75 billion of "all risk" nuclear property insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage limit is $2.25 billion . In addition, the Company has secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo Verde.
Fossil-Fueled Plants
The Newman Power Station ("Newman") consists of three conventional steam-electric generating units and two combined cycle generating units. The station operates primarily on natural gas but the conventional steam-electric generating units can also operate on fuel oil.
The Company's Rio Grande Power Station ("Rio Grande") consists of three conventional steam-electric generating units and one aeroderivative unit that operate on natural gas.
The Company's Montana Power Station ("MPS") consists of four aeroderivative generating units which operate on natural gas. The units can also operate on fuel oil.
The Company's Copper Power Station ("Copper") consists of a natural gas combustion turbine used primarily to meet peak demand.
The Company owned a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners"). The Company shared power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. On February 17, 2015, the Company and APS entered into an asset purchase agreement ( the " Purchase and Sale Agreement ") providing for the sale of the Company’s interests in Four Corners to APS. Four Corners continued to provide energy to serve the Company's native load up to the closing date of the sale on July 6, 2016 . Also on July 6, 2016, prior to the

4


closing of the transaction, the Company and APS entered into an amendment to the Purchase and Sale Agreement pursuant to which APS assigned its right, title and interest in the Purchase and Sale Agreement to its affiliate 4C Acquisition, LLC ("APS's affiliate"), and Pinnacle West Capital Corporation, the parent company of APS and APS's affiliate ("Pinnacle West"), guaranteed APS's affiliate's obligations under the Purchase and Sale Agreement. The sales price was $32.0 million , which was based on the net book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million , respectively, to reflect the assumption by APS's affiliate of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses. The sales price was also adjusted downward by approximately $1.3 million for estimated closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing, the Company received approximately $4.2 million in cash, subject to post-closing adjustments. No significant gain or loss was recorded after the closing date. APS's affiliate assumed responsibility for all Four Corners capital expenditures made after July 6, 2016, which assumption is guaranteed by Pinnacle West. In addition, APS's affiliate will indemnify the Company against certain liabilities and costs related to the future operation of Four Corners, which indemnification is guaranteed by Pinnacle West. See Part II, Item 8, "Financial Statements and Supplementary Data, Note C and Note E of Notes to Financial Statements" for further discussions.
Wind and Solar Photovoltaic Facilities
The Company’s Hueco Mountain Wind Ranch consisted of two wind turbines with a total capacity of 1.32 MW. The two wind turbines were decommissioned in June 2016. The Company also owns six solar photovoltaic facilities with a total capacity of 0.2 MW.
Transmission and Distribution Lines and Agreements
The Company owns, or has significant ownership interests in, four 345 kV transmission lines in New Mexico and Arizona and three 500 kV lines in Arizona. These lines enable the Company to deliver its energy entitlements from its remote generation sources at Palo Verde and, prior to July 6, 2016, Four Corners, to its service area (pursuant to various transmission and power exchange agreements to which the Company is a party). The Company also owns the transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. Pursuant to standards established by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, the Company operates its transmission system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service.
In addition to the transmission and distribution lines within our service territory, the Company's transmission network and associated substations include the following:
Line
 
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's ("TEP") Springerville Generating Plant near Springerville, Arizona, to the Company's Diablo Substation near Sunland Park, New Mexico.
(2)
Runs from Public Service Company of New Mexico ("PNM") West Mesa Substation located near Albuquerque, New Mexico, to the Company's Arroyo Substation located near Las Cruces, New Mexico.
(3)
Runs from TEP's Greenlee Substation located near Duncan, Arizona to Newman.
(4) Runs from the Company's and PNM's high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico.
(5)
Represents two 45-mile, 500 kV lines running from Palo Verde to the Westwing Substation located northwest of Phoenix near Peoria, Arizona.
(6) Runs from Palo Verde to the Jojoba Substation located near Gila Bend, Arizona, then to the Kyrene Substation located near Tempe, Arizona.

5


Environmental Matters
General . The Company is subject to extensive laws, regulations and permit requirements with respect to air and GHG emissions, water discharges, soil and water quality, waste management and disposal, natural resources and other environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation, or the introduction of new laws and regulations, and, as a result, the Company may face additional capital and operating costs to comply. Certain key environmental issues, laws and regulations facing the Company are described further below.
Air Emissions. The U.S. Clean Air Act ("CAA"), associated regulations and comparable state and local laws and regulations relating to air emissions impose, among other obligations, limitations on pollutants generated during the operations of the Company's facilities and assets, including sulfur dioxide ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury.
Cross State Air Pollution Rule . The U.S. Environmental Protection Agency (the "EPA") promulgated the Cross-State Air Pollution Rule ("CSAPR") in August 2011, which involves requirements to limit emissions of NOx and SO2 from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions. CSAPR was intended to replace the EPA's 2005 Clean Air Interstate Rule ("CAIR"). The U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") vacated CSAPR in August 2012 and allowed CAIR to stand until the EPA issued a proper replacement. On April 29, 2014, the U.S. Supreme Court reversed and upheld CSAPR, remanding certain portions of CSAPR to the D.C. Circuit for further consideration. On July 28, 2015, the D.C. Circuit ruled that the EPA's emissions budgets for 13 states, including Texas, are invalid but left the rule in place on remand. On October 26, 2016, the EPA published its final CSAPR Update Rule with an effective date of December 27, 2016. While we are unable to determine the full impact of this rule at this time, the Company believes it is currently positioned to comply with CSAPR.
National Ambient Air Quality Standards ( " NAAQS ") . Under the CAA, the EPA sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including PM, NOx, carbon monoxide ("CO"), ozone and SO2. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA tightened the NAAQS for both nitrogen dioxide ("NO2") and SO2. The EPA is considering a 1-hour secondary NAAQS for NO2 and SO2. In January 2013, the EPA tightened the NAAQS for fine PM. On October 1, 2015, following on its November 2014 proposal, EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion ("ppb") to 70 ppb. Ozone is the main component of smog. While not directly emitted into the air, it forms from precursors, including NOx and volatile organic compounds, in combination with sunlight. The EPA is scheduled to make attainment/nonattainment designations for the revised ozone standards by October 1, 2017. While it is currently unknown how the areas in which we operate will be designated, for nonattainment areas classified as "Moderate" and above, states, and any tribes that choose to do so, are expected to be required to complete development of implementation plans in the 2020-2021 timeframe. Most nonattainment areas are expected to have until 2020 or 2023 to meet the primary (health) standard, with the exact attainment date varying based on the ozone level in the area. The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the NAAQS, individually or in the aggregate, could have a material impact on its operations and financial results.
Other Laws and Regulations and Risks . The Company sold its interest in Four Corners to APS's affiliate on July 6, 2016 at the expiration of the 50-year participation agreement. As of the closing date of the sale, the Company’s environmental liabilities associated with Four Corners were limited to conditions that existed at the time of the sale and further limited to the portion thereof for which the Company would have been financially responsible if Four Corners had fully ceased operation on July 6, 2016. As the Company no longer owns any coal-fired generation as a result of the sale, it believes it is not responsible for a significant portion of the compliance or ongoing operational costs associated with the Mercury and Air Toxics Standards ("MATS"), the Coal Combustion Residue ("CCR") Rule, or the revised Wastewater Effluent Limitation Guidelines ("ELG"), which had been identified in previous filings that the Company has made with the SEC. Pursuant to the terms of the Purchase and Sale Agreement, neither APS's affiliate nor APS assumed the Company's pre-closing obligations under environmental laws with respect to its interest in Four Corners. Similar to other former owners of real property, the Company may be subject to certain future claims under environmental laws and regulations as former owner of Four Corners. The extent of such claims, if any, cannot be predicted with certainty.
Climate Change. In recent years, there has been increasing public debate regarding the potential impact on global climate change. There has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of GHG and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, in April 2016

6


the United States signed the Paris Agreement, which requires countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020.
The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting GHG emissions, including carbon dioxide. In particular, the U.S. Congress has considered legislation to restrict or regulate GHG emissions. In the past few years, the EPA began using the CAA to regulate carbon dioxide and other GHG emissions, such as the 2009 GHG Reporting Rule and the EPA’s sulfur hexafluoride ("SF6") reporting rule, both of which apply to the Company, as well as the EPA’s 2010 actions to impose permitting requirements on new and modified sources of GHG emissions. In October 2015, the EPA published a final rule establishing new source performance standards ("NSPS") limiting CO2 emissions from new, modified and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February 9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. On September 27, 2016, the case against the CPP was heard in the United States Court of Appeals for the District of Columbia Circuit. We cannot at this time determine the impact of the CPP and related rules and legal challenges may have on our financial position, results of operations or cash flows.
While a significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes that its GHG emissions are low relative to electric power companies who rely more on coal-fired generation, current and future legislation and regulation of GHG or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduce demand for the power the Company generates, and/or require the Company to purchase rights to emit GHG, any of which could be material to the Company's business, reputation, financial condition or results of operations.
Climate change also has potential physical effects that could be relevant to the Company's business. In particular, some studies suggest that climate change could affect the Company's service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment. The Company believes that material effects on the Company's business or results of operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible to meaningfully quantify the costs of these potential impacts at present.
Environmental Litigation and Investigations . Since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. District Court for New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S. District Court for New Mexico entered the CAA Settlement Agreement. The agreement imposes a total civil penalty payable by the co-owners of Four Corners collectively in the amount of $1.5 million , and it requires the co-owners to pay $6.7 million for environmental mitigation projects. At December 31, 2016, the Company has accrued its remaining unpaid share of approximately $0.2 million related to this matter.
Construction Program
Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems, and the cost of capital improvements and replacements at Palo Verde. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system and to replace retiring plants and terminated purchased power agreements, the costs of which are included in the table below.

7


The Company’s estimated cash construction costs for 2017 through 2021 are approximately $1.1 billion. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.  
    
By Year (1)(2)
(estimates in millions)
 
By Function
(estimates in millions)
2017
$
215

 
Production (1)(2)
$
492

2018
185

 
Transmission
131

2019
203

 
Distribution
349

2020
240

 
General
113

2021
242

 
 
 
Total
$
1,085

 
Total
$
1,085

__________________________
(1)
Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel."
(2)
Estimated production costs consist of:
a.
$273 million for new generating capacity, including:
i.
$253 million of construction costs from 2018 through 2021 for a 320 MW generating resource scheduled for completion in 2023.
ii.
$20 million for two utility-scale solar energy generating facilities which would have a combined maximum capacity of up to 8 MW.
b.
$219 million of other generation costs, including $191 million for Palo Verde.





8


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 of the Company.
        
 
Years Ended December 31,
 
2016
 
2015
 
2014
Power Source
(percentage of total kWh energy mix)
Nuclear
49
%
 
47
%
 
47
%
Natural gas
34
%
 
34
%
 
35
%
Coal
2
%
 
6
%
 
5
%
Purchased power
15
%
 
13
%
 
13
%
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 "Regulation – New Mexico Regulatory Matters."
Nuclear Fuel     
The nuclear fuel cycle for Palo Verde consists of the following stages:  the mining and milling of uranium ore to produce uranium concentrates, the conversion of the uranium concentrates to uranium hexafluoride ("conversion services"), the enrichment of uranium hexafluoride ("enrichment services"), the fabrication of fuel assemblies ("fabrication services"), the utilization of the fuel assemblies in the reactors, and the storage and disposal of the spent fuel. 
Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Palo Verde Participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The Palo Verde Participants have contracted for 100% of Palo Verde's requirements for uranium concentrates and conversion services through 2018 and 45% of its requirements in 2019-2025. The participants have also contracted for 100% of Palo Verde's enrichment services through 2020, 20% of its enrichment services for 2021-2026 and all of Palo Verde's fuel assembly fabrication services through 2024. 
Nuclear Fuel Financing . The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust ("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. RGRT has $95 million aggregate principal amount borrowed in the form of senior notes, of which $50 million will mature in August 2017. The Company expects to repay the $50 million of senior notes upon maturity with borrowings under the Company’s revolving credit facility (the "RCF") or refinance them. The Company guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing requirements of RGRT are met with a combination of the senior notes and short-term borrowings under the RCF.
Natural Gas
The Company manages its natural gas requirements through a combination of a long-term (greater than a year) supply contract, several medium-term (greater than a month but less than one year) supply contracts and spot or short-term (daily to a month) market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. Medium-term and spot agreements are either fixed priced and/or index priced depending on the market. In 2016, the Company’s natural gas requirements at Newman, Rio Grande and MPS were met with short-term, medium-term and long-term natural gas purchases from various suppliers, and this practice is expected to continue in 2017. Interstate gas is delivered under a base firm transportation contract. The Company has expanded its firm interstate transportation contract to include MPS. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for Newman, Rio Grande and MPS. The Company will continue to evaluate the availability of short-term natural gas supplies versus medium and long-term supplies to maintain a reliable and economical supply for its local generating stations.
Natural gas for Newman and Copper is also supplied pursuant to a long-term intrastate natural gas contract that became effective October 1, 2009 and continues through 2017.

9


Purchased Power
To supplement its own generation and operating reserve requirements, and to meet required renewable portfolio standards, the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the Company’s resource needs, the economics of the transactions and specific renewable portfolio requirements.
The Company has a firm 100 MW Power Purchase and Sale Agreement (the "Power Purchase and Sale Agreement") with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport"), pursuant to which Freeport will deliver energy to the Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and the Company will deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to the contracted MW amount at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. The Power Purchase and Sale Agreement was approved by the Federal Energy Regulatory Commission ("FERC") and will continue through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold thereunder. The parties have agreed to increase the amount up to 125 MW through December 2018.
The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements. Specifically, the Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico, which began commercial operation in July 2011. In June 2015, the Company entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement photovoltaic modules. The Company also entered into a 20-year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico, which began commercial operation in August 2011. In addition, the Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunE EPE1, LLC (10 MW) and SunE EPE2, LLC (12 MW), which began commercial operation in June 2012 and May 2012, respectively.
Furthermore, the Company has a 20-year purchase power agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico which began commercial operation in May 2014. Finally, the Company has a 30-year purchase power agreement with Newman Solar LLC to purchase the total output, which is approximately 10 MW, from a solar photovoltaic generation plant on land subleased from the Company in proximity to Newman. This solar project began commercial operation in December 2014.
Other purchases of shorter duration were made during 2016 to supplement the Company's generation resources during planned and unplanned outages, for economic reasons and to supply off-system sales.

10


Operating Statistics
 
Years Ended December 31,
 
2016
 
2015
 
2014
Operating revenues (in thousands):
 
 
 
 
 
Non-fuel base revenues:
 
 
 
 
 
Retail:
 
 
 
 
 
Residential
$
278,774

 
$
246,265

 
$
234,371

Commercial and industrial, small
194,942

 
187,436

 
185,388

Commercial and industrial, large
39,070

 
40,411

 
39,239

Sales to public authorities
96,881

 
91,244

 
92,066

Total retail base revenues
609,667

 
565,356

 
551,064

Wholesale:
 
 
 
 
 
Sales for resale
2,407

 
2,455

 
2,277

Total non-fuel base revenues
612,074

 
567,811

 
553,341

Fuel revenues:
 
 
 
 
 
Recovered from customers during the period
148,397

 
127,765

 
161,052

Under (over) collection of fuel
14,893

 
(13,342
)
 
3,110

New Mexico fuel in base rates
33,279

 
72,129

 
71,614

Total fuel revenues
196,569

 
186,552

 
235,776

Off-system sales:
 
 
 
 
 
Fuel cost
38,933

 
52,406

 
74,716

Shared margins
5,632

 
11,048

 
21,117

Retained margins
1,137

 
1,362

 
2,147

Total off-system sales
45,702

 
64,816

 
97,980

Other
32,591

 
30,690

 
30,428

Total operating revenues
$
886,936

 
$
849,869

 
$
917,525

Number of customers (end of year) (1):
 
 
 
 
 
Residential
363,987

 
358,819

 
353,885

Commercial and industrial, small
41,741

 
40,367

 
40,038

Commercial and industrial, large
49

 
49

 
49

Other
5,285

 
5,261

 
5,017

Total
411,062

 
404,496

 
398,989

Average annual kWh use per residential customer
7,748

 
7,763

 
7,496

Energy supplied, net, kWh (in thousands):
 
 
 
 
 
Generated
8,820,006

 
9,585,089

 
9,477,129

Purchased and interchanged
1,552,251

 
1,390,946

 
1,390,490

Total
10,372,257

 
10,976,035

 
10,867,619

Energy sales, kWh (in thousands):
 
 
 
 
 
Retail:
 
 
 
 
 
Residential
2,805,789

 
2,771,138

 
2,640,535

Commercial and industrial, small
2,403,447

 
2,384,514

 
2,357,846

Commercial and industrial, large
1,030,745

 
1,062,662

 
1,064,475

Sales to public authorities
1,572,510

 
1,585,568

 
1,562,784

Total retail
7,812,491

 
7,803,882

 
7,625,640

Wholesale:
 
 
 
 
 
Sales for resale
62,086

 
63,347

 
61,729

Off-system sales
1,927,508

 
2,500,947

 
2,609,769

Total wholesale
1,989,594

 
2,564,294

 
2,671,498

Total energy sales
9,802,085

 
10,368,176

 
10,297,138

Losses and Company use
570,172

 
607,859

 
570,481

Total
10,372,257

 
10,976,035

 
10,867,619

Native system:
 
 
 
 
 
Peak load, kW
1,892,000

 
1,794,000

 
1,766,000

Net dependable generating capability for peak, kW
2,080,000

 
2,055,000

 
1,879,000

Total system:
 
 
 
 
 
Peak load, kW (2)
2,027,000

 
1,992,000

 
1,953,000

Net dependable generating capability for peak, kW
2,080,000

 
2,055,000

 
1,879,000

___________________________
(1)
The number of retail customers presented is based on the number of service locations.
(2)
Includes spot sales and net losses of 135,000 kW, 198,000 kW and 187,000 kW for 2016, 2015 and 2014, respectively.

11


Regulation
General
The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. Municipal orders, ordinances and other agreements regarding rates and services adopted by Texas municipalities are subject to review and approval by the PUCT. The FERC has jurisdiction over the Company's wholesale (sales for resale) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and the FERC are subject to judicial review.
Texas Regulatory Matters
2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities incorporated in its Texas service territory, and the PUCT in Docket No. 44941, a request for an annual increase in non-fuel base revenues (the "2015 Texas Retail Rate Case").
On July 21, 2016, the parties to PUCT Docket No. 44941 filed the Joint Motion to Implement Uncontested Amended and Restated Stipulation and Agreement which was unopposed by the parties (the "Unopposed Settlement"). On August 25, 2016, the PUCT approved the Unopposed Settlement and issued its final order in Docket No. 44941 (the "PUCT Final Order"), as proposed. The PUCT Final Order provided for: (i) an annual non-fuel base rate increase, lower annual depreciation expense, a revised return on equity for AFUDC purposes, and the inclusion of substantially all new plant in service in rate base; (ii) an additional annual non-fuel base rate increase of $3.7 million related to Four Corners costs, which will be collected through a surcharge terminating on July 12, 2017; (iii) removing the separate rate treatment for residential customers with solar systems that the Company had proposed in its August 10, 2015 filing; (iv) allowing the Company to recover $3.1 million in rate case expenses through a separate surcharge and (v) allowing the Company to recover revenues associated with the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 through a separate surcharge.
Interim rates, associated with the annual non-fuel base rate increase, became effective on April 1, 2016. The additional surcharges associated with the incremental Four Corners costs, rate case expenses and the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 were implemented on October 1, 2016.
For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. The effects of the PUCT Final Order on operating results for the year ended December 31, 2016 increased operating revenues by $42.4 million, decreased depreciation expense by $10.3 million and decreased other expenses, net by approximately $2.7 million for an aggregate increase in income before income taxes of $50.0 million and an increase in net income of $27.3 million.
2017 Texas Retail Rate Case Filing. On February 13, 2017, the Company filed with the City of El Paso, other municipalities incorporated in the Company's Texas service territory and the PUCT in Docket No.46831, a request for an increase in non-fuel base revenues of approximately $42.5 million . The Company invoked its statutory right to have its new rates relate back for consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT 's final order in Docket No. 46831 . The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. The Company cannot predict the outcome or the timing of this rate case at this time.
Energy Efficiency Cost Recovery Factor. On May 1, 2015, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and a true-up to prior year actual costs, the Company requested approval of a $1.0 million bonus for the 2014 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 44677. A stipulation and settlement agreement was filed September 24, 2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT included a performance bonus of $1.0 million . The Company recorded the performance bonus in operating revenues in the fourth quarter of 2015.
On April 29, 2016, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2017. In addition to projected energy efficiency costs for 2017 and true-up to prior year actual costs, the Company requested approval of a $0.7 million bonus for the 2015 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 45885. Parties in the proceeding, including PUCT staff and the City of El Paso, filed a settlement in the case that approved the Company's proposal with a reduction to the 2015 program bonus of $0.2 million . The PUCT approved the settlement on October 28, 2016. The settlement approved by the PUCT included a performance bonus of $0.5 million which was recorded in operating revenues in the third quarter of 2016.

12


Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.
On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect reduced fuel expenses primarily related to a reduction in the price of natural gas used to generate power. The over-recovered balance was below the PUCT's materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015.
On November 30, 2016, the Company filed a request, which was assigned PUCT Docket No. 46610, to increase its fixed fuel factor by approximately 28.8% to reflect increased fuel expenses primarily related to an increase in the price of natural gas used to generate power. The increase in the fixed fuel factor was effective on an interim basis January 1, 2017 and approved by the PUCT on January 10, 2017. As of December 31, 2016, the Company had under-recovered fuel costs in the amount of $11.1 million for the Texas jurisdiction.
Fuel Reconciliation Proceeding . On September 27, 2016, the Company filed an application with the PUCT, designated as PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 31, 2016. A procedural schedule has been adopted with hearings in April 2017. As of December 31, 2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $114.4 million . The Company cannot predict the outcome or the timing of this matter.
Montana Power Station Approvals. The Company received Certificate of Convenience and Necessity ("CCN") approval from the PUCT to construct four natural gas fired generating units at MPS in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the EPA . MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in March 2015 . MPS Units 3 and 4 were completed and placed into service on May 3, 2016 and September 15, 2016 , respectively.
Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program that includes the construction and ownership of a 3 MW solar photovoltaic system located at MPS. Participation will be on a voluntary basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT Docket No. 44800. The Company filed a settlement agreement among all parties on July 1, 2016 approving the program, and the PUCT approved the settlement agreement and program on September 1, 2016. The Company expects completion of the solar facility and commencement of the program in the second quarter of 2017.
Four Corners . On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the sale of the Company's interest in Four Corners to APS. The sale of the Company's interest in Four Corners closed on July 6, 2016 . See Part II, Item 8, " Financial Statements and Supplementary Data, Note E of Notes to Financial Statements" for further details on the sale of Four Corners.
On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and certain rate and accounting findings related to the Purchase and Sale Agreement. This case was assigned PUCT Docket No. 44805. Subsequent to the filing of the application, the case has been subject to numerous procedural matters, including a March 23, 2016 order in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the requested rate and accounting findings, including mine reclamation costs, in a rate case proceeding. On September 1, 2016, a motion by parties in the proceeding to suspend the procedural schedule in order to pursue settlement was approved, and the parties are engaged in settlement discussions.
At December 31, 2016, the regulatory asset associated with the Four Corners mine reclamation costs for the Company's Texas jurisdiction was approximately $7.3 million . The Company currently continues to recover its mine reclamation costs in Texas under previous orders and decisions of the PUCT. If any future determinations made by the Company's regulators result in changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions.

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Other Required Approvals . The Company has obtained other required approvals for tariffs and approvals required by the Public Utility Regulatory Act (the "PURA") and the PUCT.
New Mexico Regulatory Matters
2015 New Mexico Rate Case Filing . On May 11, 2015, the Company filed a request with the NMPRC, in Case No. 15-00127-UT, for an annual increase in non-fuel base rates. On June 8, 2016, the NMPRC issued its final order in Case No. 15-00127-UT (the "NMPRC Final Order") which approved an annual increase in non-fuel base rates of approximately $0.6 million , an increase of approximately $0.5 million in other service fees and a decrease in the Company's allowed return on equity to 9.48% . The NMPRC Final Order concluded that all of the Company's new plant in service was reasonable and necessary and therefore would be recoverable in rates. The Company's rates were approved by the NMPRC effective July 1, 2016 and implemented at such time.
2017 New Mexico Rate Case Filing . NMPRC Case No. 15-00109-UT requires the Company to make a rate filing in New Mexico in the second quarter of 2017 using a historical test year ended December 31, 2016.
Fuel and Purchased Power Costs. On January 8, 2014, the NMPRC approved the continuation of the Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") without modification in NMPRC Case No. 13-00380-UT. Historically, fuel and purchased power costs were recovered through base rates and a FPPCAC that accounts for changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the final order in Case No. 15-00127-UT, fuel and purchased power costs are no longer recovered through base rates but are recovered through the FPPCAC. Fuel and purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the FPPCAC as purchased power using a proxy market price approved in Case No. 13-00380-UT. The Company's request to reconcile its fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in Case No. 15-00127-UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2016 that total approximately $114.6 million . At December 31, 2016, the Company had a net fuel over-recovery balance of $0.2 million in New Mexico .
Montana Power Station Approvals. The Company received CCNs from the NMPRC to construct four units at MPS and the associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the EPA. A final order in NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in March 2015 . MPS Units 3 and 4 were completed and placed into service on May 3, 2016 and September 15, 2016 , respectively.
Four Corners. On June 15, 2016, in NMPRC Case No. 15-00109-UT, the NMPRC issued its final order approving the Company's sale and abandonment of its ownership interest in Four Corners to APS pursuant to a February 17, 2015 Purchase and Sale Agreement between the Company and APS. See Part II, Item 8, " Financial Statements and Supplementary Data, Note E of Notes to Financial Statements" for further details on the sale of Four Corners.
5 MW HAFB Facility CCN. On October 7, 2015, in NMPRC Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a 5 MW solar power generation facility located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a special retail contract, which includes power sales agreement for the facility, to replace the existing load retention agreement which was approved by final order issued October 5, 2016 in NMPRC Case No. 16-00224-UT. Construction of the solar generation facility is expected to be completed in the second quarter of 2017.
Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case No. 15-00280-UT to issue up to $310.0 million of new long-term debt and to guarantee the issuance of up to $65.0 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval supersedes prior approvals. Under this authorization, on March 24, 2016 , the Company issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044 . The net proceeds from the issuance of these senior notes, after deducting the underwriters' commission, were $158.1 million . These proceeds include accrued interest of $2.4 million and a $7.1 million premium before expenses. These senior notes constitute an additional issuance of the Company's 5.00% Senior Notes due 2044 , of which $150.0 million was previously issued on December 1, 2014 , for a total principal amount outstanding of $300.0 million .
Other Required Approvals . The Company has obtained other required approvals for other tariffs, securities transactions, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC.

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Federal Regulatory Matters
Four Corners. On June 26, 2015, APS filed an application requesting authorization from FERC to purchase 100% of the Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and rights. On December 22, 2015, FERC issued an order approving the proposed transaction. The sale of the Company's interest in Four Corners closed on July 6, 2016 . See Part II, Item 8, " Financial Statements and Supplementary Data, Note E of Notes to Financial Statements" for further details on the sale of Four Corners.
Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under the RCF up to $400.0 million outstanding at any time, to issue up to $310.0 million in long-term debt, and to guarantee the issuance of up to $65.0 million of new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from November 15, 2015 through November 15, 2017. This approval supersedes prior approvals.
Under this authorization, on March 24, 2016, the Company issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044 . Additionally under this authorization, on January 9, 2017, the Company exercised its option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50.0 million to $350.0 million . The Company still has the option to extend the facility by one additional year to January 2021 and to increase the RCF by up to $50.0 million (up to a total of $400.0 million ) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. Additionally, the Company agreed to reduce the letters of credit commitment to $50.0 million from a total commitment, under the RCF, of $350.0 million .
Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC.
United States Department of Energy. The DOE regulates the Company's exports of power to the Comisión Federal de Electricidad in Mexico pursuant to a license and two presidential permits issued by the DOE.
The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See "Facilities – Palo Verde" for discussion of spent fuel storage and disposal costs.

Sales for Resale

The Company provides firm capacity and associated energy to the Rio Grande Electric Cooperative ("RGEC") pursuant to an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission service to the RGEC pursuant to the Company's Open Access Transmission Tariff ("OATT"). The contract includes a formula-based rate that is updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC.
Power Sales Contracts
The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2016.

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Franchises and Significant Customers
Franchises
The Company operates under franchise agreements with several cities in its service territory, including one with El Paso, Texas, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its customers within El Paso. Pursuant to the El Paso franchise agreement, which was amended in 2010, the Company pays to the City of El Paso, on a quarterly basis, a fee equal to 4.00% of gross revenues the Company receives for the generation, transmission and distribution of electrical energy and other services within the city. The 2005 El Paso franchise agreement set the franchise fee at 3.25% of gross revenues, but the 2010 amendment added an incremental fee equal to 0.75% of gross revenues to be placed in a restricted fund to be used by the city solely for economic development and renewable energy purposes. Any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso. The El Paso franchise agreement is set to expire on July 31, 2030 .
The Company does not have a written franchise agreement with the City of Las Cruces, the second largest city in its service territory. The Company provides electric distribution service to the City of Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009 . The Company pays the City of Las Cruces a franchise fee of 2.00% of gross revenues the Company receives from services within the City of Las Cruces.
Military Installations
The Company serves HAFB, White Sands and Fort Bliss. These military installations represent approximately 2.8% of the Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss under which Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs . The Company serves White Sands under the applicable New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under which the Company provides retail electric service and limited wheeling services to HAFB under the applicable New Mexico tariffs. As stated in the contract, HAFB will purchase the full output of a Company-owned 5 MW solar facility upon its completed construction, with HAFB's other power requirements provided under the applicable New Mexico tariffs.
Other Information
Investors should note that we announce material financial information in our filings with the SEC, press releases and public conference calls. Based on guidance from the SEC, we may also use the Investor Relations section of our website (www.epelectric.com) to communicate with investors about the Company. It is possible that the financial information we post there could be deemed to be material information. The information contained on or accessible from our website is not incorporated by reference into and does not constitute a part of this Annual Report on Form 10-K.        

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Item 1A.    Risk Factors
Like other companies in our industry, our financial results are impacted by weather, the economy of our service territory, market prices for power, fuel prices, and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by local, regional and national macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this Annual Report on Form 10-K and in our other filings with the SEC.
Our Revenues and Profitability Depend Upon Regulated Rates
Our retail rates are subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. The PUCT Final Order established our current retail base rates in Texas, effective January 12, 2016. In addition, the NMPRC Final Order established rates in New Mexico that became effective in July 2016.
Our profitability depends on our ability to recover the costs, including a reasonable return on invested capital, of providing electric service to our customers through base rates approved by our regulators. These rates are generally established based on an analysis of the expenses we incur in a historical test year, and as a result, the rates ultimately approved by our regulators may or may not match our expenses at any given time and recovery of expenses may lag behind the occurrence of those expenses. Rates in New Mexico may be established using projected costs and investment for a future test year period in certain instances. While rate regulation is based on the assumption that we will have a reasonable opportunity to recover our costs and earn a reasonable rate of return on our invested capital, there can be no assurance that our future Texas rate cases or New Mexico rate cases will result in base rates that will allow us to fully recover our costs including a reasonable return on invested capital. There can be no assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including costs associated with future plant retirements. It is also likely that third parties will intervene in any rate cases and challenge whether our costs are reasonable and necessary. If all of our costs are not recovered, or timely recovered, through the retail base rates ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely affect our ability to meet our financial obligations.
On February 13, 2017, we filed a general base rate case with the PUCT, Docket No. 46831 (the “2017 Texas rate case”), respectively, to establish new rates and to request recovery of new plant placed into service since April 2015 of approximately $444 million and to recover other cost of service increases. We anticipate that third parties will intervene in the 2017 Texas rate case and we expect them to challenge the reasonableness and necessity of certain of our costs. While we cannot predict the outcome or the timing of the 2017 Texas rate case at this time, we invoked our statutory right to have new rates relate back for consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT's final order in the 2017 Texas rate case. The PUCT has the authority to require us to surcharge or refund such differences over a period not to exceed 18 months. If the PUCT does not increase our rates adequately, our future operations, cash flow and financial condition could be materially and adversely affected. For a full discussion of these rate cases see Part II, Item 8, "Financial Statements and Supplementary Data, Note C of Notes to Financial Statements."
We May Not Be Able To Recover All Costs of New Generation and Transmission Assets
We received approval, both from the PUCT and the NMPRC, to construct Units 3 and 4, two 89 MW simple-cycle aeroderivative combustion turbines at MPS. In 2016, we completed construction of these units, which began commercial operation in May 2016 and September 2016, respectively. We are exposed to the risk of failing to recover all costs associated with the construction of MPS Units 3 and 4 and other new units and transmission assets.
In 2014 and 2016, we issued $150.0 million in aggregate principal amount of 5.00% Senior Notes, due December 1, 2044 for a total principal amount outstanding of $300.0 million. The net proceeds from the 5.00% Senior Notes along with borrowings under our RCF were used to fund the construction of MPS and other capital additions. The costs of financing and constructing these assets are subject to review by the PUCT and NMPRC. To the extent that the PUCT or the NMPRC determines that the costs of construction are not reasonable because of cost overruns, delays or other reasons, we may not be allowed to recover these costs from customers in base rates.
In addition, if future units are not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the PUCT and the NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting from delays in the completion of these new units or other new units.

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Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital Programs and Increase Our Funding Obligations for Pensions and Decommissioning
In recent years, the global credit and equity markets and the overall economy have been extremely volatile. These and future events could have a number of effects on our operations and capital programs. For example, tight credit and capital markets could make it difficult and more expensive to raise capital to fund our operations and capital programs. If we are unable to access the credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in the stock market performance may reduce the value of our financial assets and decommissioning trust investments. Similarly, inflationary increases will increase our future decommission obligations. Such market results may also increase our funding obligations for our pension plans, other post-retirement benefit plans and nuclear decommissioning trusts. Changes in the corporate interest rates that we use as the discount rate to determine our pension and other post-retirement liabilities may have an impact on our funding obligations for such plans and trusts. Further, continued economic volatility may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. Uncertainty in the credit markets may negatively impact the ability of our customers to finance purchases of our services and could adversely affect the collectability of our receivables. Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. For example, during 2013, sales to public authorities and small commercial and industrial customers were negatively impacted by the federal government sequestration and shutdown. The credit markets and overall economy may also adversely impact the financial health of our suppliers. If that were to occur, our access to and prices for inventory, supplies and capital equipment could be adversely affected. Our power trading counterparties could also be adversely impacted by the market and economic conditions which could result in reduced wholesale power sales or increased counterparty credit risk. Declines in revenues, earnings and cash flow from these events, could impact our ability to fund construction expenditures and impact the level of dividend payments.
There are Inherent Risks in the Ownership of Nuclear Facilities
Our 15.8% ownership interest in Palo Verde, which is the largest nuclear electric generating facility in the United States, subjects us to a number of risks. A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 30% of our available net generating capacity and provided approximately 49% of our energy requirements for the twelve months ended December 31, 2016. Palo Verde comprises approximately 25% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and costs at Palo Verde. Palo Verde operated at a capacity factor of 93.2% and 94.3% in the twelve months ended December 31, 2016 and 2015, respectively.
We participate in Palo Verde with one or more parties who may not have the same goals, strategies, priorities or resources as we do and may compete with us. Furthermore, regulatory compliance issues and financial restraints could cause these parties to make decisions that could potentially be adverse to us.
As Palo Verde is a nuclear electric generating facility it is subject to environmental, health and financial risks, such as the ability to obtain adequate supplies of nuclear fuel and water; the ability to dispose of spent nuclear fuel; increases in decommissioning costs due to inflation and regulatory changes, the ability to maintain adequate trust fund reserves for decommissioning; potential liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; cyber attacks, or other causes; and unscheduled outages due to equipment and other problems. If a nuclear incident were to occur at Palo Verde, it could materially and adversely affect our results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause regulatory bodies to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.
We May Not Be Able to Recover All of Our Fuel Expenses from Customers On a Timely Basis Or at All
In general, by law, we are entitled to recover our reasonable and necessary fuel and purchased power expenses from our customers in Texas and New Mexico. NMPRC Case No. 13-00380-UT provides for energy delivered to New Mexico customers from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon a previous purchased power contract. Fuel and purchased power expenses in Texas and New Mexico are subject to reconciliation by the PUCT and NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs such that fuel revenues equal recoverable fuel and purchased power expense including the re-priced energy costs for Palo Verde Unit 3 in New Mexico. In the event that recovery of fuel and purchased power expenses is denied in any reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would incur a loss to the extent of the disallowance.

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In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. In Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods of significant increases in natural gas prices, we realize a lag in the ability to reflect increases in fuel costs in our fuel recovery mechanisms in Texas. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely recovery of such costs, we could experience a material negative impact on our cash flow.
Weather Conditions Affect the Demand for Electricity or Could Result in Unplanned Outages
Our service territory is in west Texas and southern New Mexico and is particularly susceptible to dry and hot temperatures in the summer months. These seasonal weather patterns result in temperatures that can lead to daytime highs exceeding 100 degrees Fahrenheit for extended periods during the summer when we typically experience peak kWh sales at higher summer rates. Milder temperatures during this period will occur occasionally and result in less kWh sales which will adversely affect our results of operations. From time to time, we experience extreme weather conditions, including high winds (usually in the spring months but can occur during other months), that may result in unplanned outages. Under such conditions, we may incur additional costs to repair and, or, to replace equipment. Depending upon the length and extent of the damage, we may also incur additional purchase power costs. Fallen power lines and poles can cause severe damage to customer property and subject us to claims, all of which could have a material adverse effect on our results of operations and cash flows.
Equipment Failures and Other External Factors Can Adversely Affect Our Results
The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure and severe weather conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these units. In the event of unplanned outages, we must acquire power from other sources at unpredictable costs in order to supply our customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to the extent of the disallowance. This could materially increase our costs and prevent us from selling excess power at wholesale. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We may also incur additional capital and operating costs in connection with the physical security and cyber security of transmission lines and generation facilities. Damage to certain transmission and generation facilities due to vandalism or other deliberate acts, or damage due to severe weather could lead to outages or other adverse effects. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. In addition, Palo Verde’s availability is an important factor in realizing off-system sales margins. These factors, as well as interest rates, economic conditions, fuel prices and price volatility could have a material adverse effect on our earnings, cash flow and financial position. While we believe we maintain adequate insurance coverage for such incidents, there is no assurance that all costs in excess of deductible amounts will be reimbursed or that we can maintain such coverage limits in the future at competitive market rates. In the event future insurance costs and/or deductible amounts increase, our financial condition, operating results and cash flows could be materially adversely affected.
Competition and Deregulation Could Result in a Loss of Customers and Increased Costs
As a result of changes in federal law, our wholesale and large retail customers have access to, in varying degrees, alternative sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. In 2004, the PUCT approved a rule delaying retail competition in our Texas service territory. This rule was codified in the PURA in June 2011. The PURA identifies various milestones that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization in the area that includes our service territory. This and other milestones are not likely to be achieved for a number of years, if at all. There is substantial uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flow and financial condition.

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Future Costs of Compliance with Environmental Laws and Regulations Could
Adversely Affect Our Operations and Financial Results
We are subject to extensive federal, state and local environmental laws and regulations relating to discharges into the air, air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources, and health and safety.  Compliance with these legal requirements, which change frequently and often become more restrictive, could require us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchases of air emission allowances and/or offsets. These laws and regulations could also result in limitations in operating hours and/or changes in construction schedules for future generating units. 
Cost of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our rates, could adversely affect our operations and financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of implementation of environmental laws or regulations. For example, the EPA has issued in the recent past various proposed regulations regarding air emissions, such as the revision of the primary and secondary ground-level ozone NAAQS. If these regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our financial results.
Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for
Electricity or Availability of Resources, and Could Result in Increased Compliance Costs
We emit GHG (including carbon dioxide) through the operation of our power plants. Federal legislation had been introduced in both houses of Congress to regulate GHG emissions and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA. Under EPA regulations finalized in May 2010, formerly known as the "Tailoring Rule", the EPA can impose GHG best achievable control technology requirements for sources, including power plants already required to implement prevention of significant deterioration under the CAA for certain other pollutants.
In addition, in October 2015, the EPA published a final rule establishing NSPS limiting CO2 emissions from new, modified and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February 9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. Further, on September 3, 2016, the U.S. signed the 21st Conference of Parties Paris Agreement, which requires countries to set and "represent a progression" in GHG emission reduction goals every five years beginning in 2020. The potential impact of this agreement and GHG rules (if and when finalized) on us is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or changes in construction schedules for future generating units.
It is not possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi-state regions or any GHG regulations adopted by the EPA or state environmental agencies will impact our business. However, any legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit GHG, and could have a material adverse effect on our business, financial condition, reputation or results of operations.
Adverse Regulatory Decisions or Changes in Applicable Regulations Could Have a Material Adverse Effect on Our
Business or Result in Significant Additional Costs
Our business is subject to extensive federal, state and local laws and regulations regarding safety and performance, siting and construction of facilities, customer service and the rates we can charge our customers, among other things. FERC regulates our wholesale operations, provision of transmission services and compliance with federally mandated reliability standards. FERC has issued a number of rules pertaining to preventing undue discrimination in transmission services and electric reliability standards. Under the Energy Policy Act of 2005, FERC can impose penalties (up to $1,213,503 per violation, per day) for failure to comply with statutes, rules and orders within FERC's jurisdiction, including mandatory electric reliability standards. Additional regulatory authorities have jurisdiction over some of our operations and construction projects, including the EPA, the DOE, the PUCT, the NMPRC and various local regulatory districts (including the cities of El Paso and Las Cruces).

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We must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective orders. Should we be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose penalties or disallowances on us, our business could be adversely affected. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to us or our facilities in a manner that may have a detrimental effect on our business or result in significant additional costs because of our obligation to comply with those requirements.
Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our Infrastructure Could Interfere With Our Operations, Could Expose Us or Our Customers or Employees to a Risk of Loss, and Could Expose Us to Liability, Regulatory Penalties, Reputational Damage and Other Harm to Our Business
We rely upon our infrastructure to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology systems for internal accounting purposes and to comply with financial reporting, legal and tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers, breaches due to employee error or malfeasance, system failures, computer viruses, natural disasters, a physical attack on our facilities, or other catastrophic events. The occurrence of any of these events could impact the reliability of our generation, transmission and distribution systems and energy marketing and trading functions; could expose us or our customers or employees to a risk of loss or misuse of confidential information; and could result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business. In addition, we may be required to incur significant costs to prevent or respond to damage caused by these disruptions or security breaches in the future.
Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. The effects of such attacks against us or others in the energy industry could increase the cost of regulatory compliance, increase the cost of insurance coverage or result in a decline in the U.S. economy which could negatively affect our results of operations and financial condition. Ongoing and future governmental efforts to regulate cybersecurity in the energy industry could lead to increased regulatory compliance costs.
The Effects of Technological Advancement, Energy Conservation Measures and Distributed Generation Could Adversely Affect Our Operations and Financial Results
New technologies may emerge that could be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant expenditures to remain competitive. Our future success will depend, in part, on our ability to anticipate and adapt to technological changes in a cost-effective manner and to offer, on a timely basis, services that meet customer demands and evolving industry standards.
Additionally, the electric utility industry is undergoing other technological advances such as the expanded cost effective utilization of energy efficiency measures and distributed generation including solar rooftop projects. Customers’ increased use of energy efficiency measures and distributed generation could result in lower demand. Reduced demand due to energy efficiency measures and the use of distributed generation, to the extent not substantially offset through ratemaking mechanisms, could have a material adverse impact on our financial condition, results of operations and cash flows.
Inflation Could Adversely Affect Our Financial Results
For the past several years, inflation has been relatively low and, therefore has had little impact on our results of operations and financial condition. However, should we experience increases in costs due to inflationary impacts, any delays in requesting and receiving compensatory increases in our base rates could have a material adverse impact on our financial condition, results of operations and cash flows.
Our Line of Business Is Concentrated Solely to the Electric Industry and to One Region
We are a fully vertically integrated electric utility company whose only business is the generation, transmission and distribution of electricity to customers in an area of approximately 10,000 square miles in west Texas and southern New Mexico. Approximately 91% of revenues are directly related to the retail sales of electric power to approximately 400,000 residential, commercial and public authority customers. As such, risks uniquely associated with the utility industry such as changes in utility legislation and regulations, weather patterns in the region and economic conditions will have a greater effect on our overall operating results than otherwise if our operations were more diversified into other lines of business and in a broader geographical area.

21


New Laws, Regulations and Policies Announced by the Trump Administration Could Impact Our Operations
President Donald Trump campaigned on a number of issues, including increasing border security and immigration regulations, overhauling federal taxes, repealing the Patient Protection Affordable Care Act, withdrawal from the Trans Pacific Partnership agreement, enacting duties on NAFTA imports and reducing the burdens of environmental and climate control regulations. Since President Trump’s inauguration, he has initiated executive orders towards achieving some of these goals; however it is uncertain to what extent President Trump proposes additional new executive orders and the effect such orders will have on the national, regional and local economies. Our service territory borders with Mexico and as such businesses in our service territory rely heavily on commerce with businesses in Mexico. Changes in regulations restricting such commerce activities could reduce our customer growth rate and materially adversely affect our results of operations, financial condition and cash flows. 
Both the new administration and the Republicans in the House of Representatives have made public statements in support of comprehensive tax reform, including significant changes to the United States corporate income tax laws. These proposed changes include, among other things, a reduction in the corporate income tax rate, the immediate deductibility of 100% of capital expenditures, and the elimination of the interest expense deduction. We are currently unable to predict whether these reform discussions will result in any significant changes to existing tax laws, or if any such changes would have a cumulative positive or negative impact on us. However, it is possible that changes in the United States federal income tax laws could have a material adverse effect on our results of operations, financial condition, and cash flows.
The Operation of Transmission Lines on Public and Private Properties, including Indian Lands, Could Result in Uncertainty Related to Continued Easements and Rights-of-way and Significantly Impact Our Business
Portions of our transmission lines are located on public and private properties, including Indian lands, pursuant to easements or other rights-of-way that are effective for specified periods. We are unable to predict the final outcome of pending or future approvals by applicable property owners and governing bodies with respect to renewals of these easements and rights-of-way.
Provisions in Our Corporate Documents, Franchise Agreements and State Law Could Delay or Prevent a Change in Control of the Company, Even if That Change Would Be Beneficial to Our Shareholders
Our Articles of Incorporation and Bylaws contain provisions that may make acquiring control of the Company difficult and could preclude our shareholders from receiving a change of control premium, including:
provisions relating to the classification, nomination and removal of our directors;
provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;
provisions limiting the ability to call special meetings of the shareholders to the Chairman of the Board, our Chief Executive Officer, our Secretary, the majority of the Board of Directors or the holders of at least 25% of the outstanding shares of our capital stock entitled to vote at such meeting;
provisions restricting our ability to engage in a wide range of “Business Combination” transactions with an “Interested Shareholder” (generally, any person who owns 15% or more of our outstanding voting power) or any affiliate or associate of an Interested Shareholder, unless specific conditions are met; and
the authorization given to our Board of Directors or any duly designated committee to issue and set the terms of preferred stock.
Our El Paso franchise agreement states that any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso. In addition, approval of the NMPRC, PUCT and FERC would likely be required in any transaction involving a change of control.
In addition, Texas law prohibits us from engaging in a business combination with any shareholder for three years from the date that person became an affiliated shareholder by beneficially owning 20% or more of our outstanding common stock, in the absence of certain board of director or shareholder approvals.


22


Item 1B.
Unresolved Staff Comments
None.


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

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

Item 4.
Mine Safety Disclosures

Not Applicable.


23


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

2016
 
 
 
 
 
 
 
First Quarter
$
46.20

 
$
37.19

 
$
45.88

 
$
0.295

Second Quarter
47.27

 
42.42

 
47.27

 
0.310

Third Quarter
48.75

 
44.07

 
46.77

 
0.310

Fourth Quarter
48.35

 
42.49

 
46.50

 
0.310


24


Performance Graph
The following graph compares the performance of the Company’s common stock to the performance of Edison Electric Institute’s ("EEI") index of investor-owned electric utilities and the NYSE Composite, setting the value of each at December 31, 2011 to a base of 100. The table sets forth the relative yearly percentage change in the Company’s cumulative total shareholder return, assuming reinvestment of dividends, as compared to EEI and the NYSE Composite, as reflected in the graph.
GRAPHA01.GIF
 
12/31/2011
 
12/31/2012
 
12/31/2013
 
12/31/2014
 
12/31/2015
 
12/31/2016
EE
100

 
96

 
109

 
128

 
127

 
158

EEI Index
100

 
102

 
115

 
149

 
143

 
168

NYSE Composite
100

 
113

 
139

 
145

 
136

 
148

As of January 31, 2017, there were 2,313 holders of record of the Company’s common stock. The Company has been paying quarterly cash dividends on its common stock since June 30, 2011 and paid a total of $49.6 million in cash dividends during the twelve months ended December 31, 2016. On January 26, 2017, the Board of Directors declared a quarterly cash dividend of $0.31 per share payable on March 31, 2017 to shareholders of record at the close of business on March 17, 2017. Typically, the Board of Directors reviews the Company’s dividend policy annually in the second quarter of each year. Declaration and payment of dividends is subject to compliance with certain financial tests under Texas law. Since 1999, the Company has also returned cash to shareholders through a stock repurchase program pursuant to which the Company has bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s program, purchases can be made at open market prices or in private transactions and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. On March 21, 2011, the Board of Directors authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock (the "2011 Plan"). No shares of common stock were repurchased during the twelve months ended December 31, 2016 under the 2011 Plan. The table below provides the amount of the fourth quarter issuer purchases of equity securities.
Period
 
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, 2016
 

 
$

 

 
393,816
November 1 to November 30, 2016
 

 

 

 
393,816
December 1 to December 31, 2016
 
5,579

 
46.50

 

 
393,816
_____________________
(a) Represents shares of common stock delivered to us as payment of withholding taxes due upon the vesting of
restricted stock held by our employees, not considered part of the 2011 Plan.
For Equity Compensation Plan Information see Part III, Item 12 – "Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters."

25


Item 6. Selected Financial Data

As of and for the following periods (in thousands except for share and per share data):
 
 
Years Ended December 31,
 
2016
 
2015
 
2014
 
2013
 
2012
Operating revenue
$
886,936

 
$
849,869

 
$
917,525

 
$
890,362

 
$
852,881

Operating income
194,861

 
$
146,191

 
$
151,163

 
$
165,635

 
$
168,658

Net income
$
96,768

 
$
81,918

 
$
91,428

 
$
88,583

 
$
90,846

Basic earnings per share:
 
 
 
 
 
 
 
 
 
Net income
$
2.39

 
$
2.03

 
$
2.27

 
$
2.20

 
$
2.27

Weighted average number of shares outstanding
40,350,688

 
40,274,986

 
40,190,991

 
40,114,594

 
39,974,022

Diluted earnings per share:
 
 
 
 
 
 
 
 
 
Net income
$
2.39

 
$
2.03

 
$
2.27

 
$
2.20

 
$
2.26

Weighted average number of shares and dilutive
 
 
 
 
 
 
 
 
 
 potential shares outstanding
40,408,033

 
40,308,562

 
40,211,717

 
40,126,647

 
40,055,581

Dividends declared per share of common stock
$
1.225

 
$
1.165

 
$
1.105

 
$
1.045

 
$
0.97

Cash additions to utility property, plant and equipment
$
225,361

 
$
281,458

 
$
277,078

 
$
237,411

 
$
202,387

Total assets (a)
$
3,376,278

 
$
3,200,607

 
$
3,033,400

 
$
2,748,139

 
$
2,637,183

Long-term debt, net of current portion (a)
$
1,195,513

 
$
1,122,660

 
$
1,122,235

 
$
988,436

 
$
987,960

Common stock equity
$
1,074,396

 
$
1,016,538

 
$
984,254

 
$
943,833

 
$
824,999

________________
(a) The Company implemented Accounting Standards Update ("ASU") 2015-03, Interest- Imputation of Interest (Topic 715) and ASU 2015-17, Balance Sheet Classification of Deferred Taxes in the first quarter of 2016, retrospectively to all periods presented in the table above.

26


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

As you read this Management’s Discussion and Analysis of Financial Condition and Results of Operations, please refer to our Financial Statements and the accompanying notes, which contain our operating results.
Summary of Critical Accounting Policies and Estimates
Our financial statements have been prepared in conformity with U.S. Generally Accepted Accounting Principles ("GAAP"). Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to Financial Statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operation.
Regulatory Accounting
We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of December 31, 2016, we had recorded regulatory assets currently subject to recovery in future rates of approximately $118.9 million and regulatory liabilities of approximately $18.4 million as discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Note D of the Notes to Financial Statements. Regulatory tax assets of approximately $66.7 million, primarily related to the regulatory treatment of the equity portion of allowance for funds used during construction ("AFUDC") and excess deferred income taxes, are included in regulatory assets.
In the event we determine that we can no longer apply the Financial Accounting Standards Board's (the "FASB") guidance for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, based on regulatory action, we could be required to record a charge against income in the amount of the unamortized balance of the related regulatory assets. Such an action could materially reduce our total assets, specifically our total deferred charges and other assets, and shareholders' equity.
Collection of Fuel Expense
In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT on a periodic basis every one to three years. The NMPRC, in its discretion, may order that a prudence review be conducted to assure that fuel and purchased power costs recovered from customers are prudently incurred. Prior to the completion of a reconciliation proceeding or audit, we record fuel transactions such that fuel revenues, including fuel costs recovered through the Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation proceeding or an audit, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.
On September 27, 2016, the Company filed an application with the PUCT, designated as PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 31, 2016. As of December 31, 2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $114.4 million. The NMPRC approved the continuation of its use of the FPPCAC without modification and the Company’s application requesting reconciliation of fuel and purchased power costs through December 2012 in Case No. 13-00380-UT. The Company's request to reconcile its fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in Case No. 15-00127-UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2016 that total approximately $114.6 million.
The Company recovers fuel and purchased power costs from the RGEC pursuant to an ongoing contract with a two-year notice to terminate provision. The contract includes a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC and is updated on an annual basis. This update is reviewed and approved by the RGEC annually

27


in February following the prior calendar year. As of December 31, 2016, the RGEC fuel costs subject to review were approximately $1.4 million.
Decommissioning Costs and Estimated Asset Retirement Obligation
Pursuant to the ANPP Participation Agreement, the rules and regulations of the Nuclear Regulatory Commission and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The determination of the estimated liability is based on site-specific estimates, which are updated every three years and involve numerous judgments and assumptions, including estimates of future decommissioning costs at current price levels, escalation rates and discount rates. The Palo Verde ARO is approximately $79.6 million and represents approximately 97% of our total ARO balance of $81.8 million as of December 31, 2016. A 10% increase in the estimates of future Palo Verde decommissioning costs at current price levels would have increased the ARO liability by approximately $7.8 million at December 31, 2016. For further details see Part II, Item 8, "Financial Statements and Supplementary Data, Note E of Notes to Financial Statements."
We are required to fund estimated nuclear decommissioning costs over the life of the generating facilities through the use of external trust funds pursuant to rules of the Nuclear Regulatory Commission, PUCT and the ANPP Participation Agreement. Historically, in Texas and New Mexico, we have been permitted to collect the funding requirements for our nuclear decommissioning trusts as part of our rates, except for a portion of Palo Verde Unit 3, which is deregulated in the New Mexico jurisdiction. While we periodically attempt to seek to recover the costs of decommissioning obligations through our rates, we are not able to conclude, given the currently available evidence, that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. We are ultimately responsible for these costs, and our future actions combined with future decisions from regulators will determine how successful we are in this effort.     
The funding amounts are based on assumptions about future investment returns and future decommissioning cost escalations. If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the nuclear plant increase beyond our expectations, we would be required to increase our funding to the nuclear decommissioning trusts.
Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $119.9 million as of December 31, 2016. A hypothetical 10% increase in interest rates would have reduced the fair values of these funds by $1.4 million at December 31, 2016. Our decommissioning trust funds also include marketable equity securities of approximately $129.8 million at December 31, 2016. A hypothetical 20% decrease in equity prices would have reduced the fair values of these funds by $26.0 million at December 31, 2016. Declines in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements.
We do not anticipate expending monies held in the nuclear decommissioning trusts before 2044 or a later period when decommissioning of Palo Verde begins.
Future Pension and Other Post-retirement Obligations
We maintain a qualified noncontributory defined benefit pension plan, which covers substantially all of our employees, and two non-funded nonqualified supplement plans that provide benefits in excess of amounts permitted under the provisions of the tax law for certain participants in the qualified plan. We also sponsor a plan that provides other post-retirement benefits, such as health and life insurance benefits to retired employees. Our net obligations under these various benefit plans at December 31, 2016 totaled $129.9 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled $3.8 million for the twelve months ended December 31, 2016.
During October 2016, we approved and communicated a plan amendment that resulted in a remeasurement of our other post-retirement benefit plan. Effective January 1, 2017, retirees and dependents that are less than 65 years of age are offered a choice between a $1,000 and $2,250 deductible plan. Additionally, retirees and dependents that are 65 years of age or greater are covered by a fully insured Medicare advantage plan. The impact of these plan changes was a reduction in the other post-retirement benefit plan obligation of $32.7 million as of December 31, 2016.
Our pension and other post-retirement benefit liabilities and the related net periodic benefit costs are calculated on the basis of a number of actuarial assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. For 2016, the discount rates used to measure our year end liabilities are based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. As of December 31, 2016, the corresponding weighted-average discount rates range from 3.76% to 4.36% depending upon the benefit plan.

28


Our overall expected long-term rate of return on assets for the pension trust fund is 7.0% effective January 1, 2017, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. Our overall expected long-term rate of return on assets for the other post-retirement benefits trust, on an after-tax basis, is 4.875% effective January 1, 2017. Both expected long-term rates of return are based on the after-tax weighted average of the expected returns on investments. The expected returns on investments in the pension trust and the other post-retirement benefits trust are based upon the target asset allocations for the two trusts.
Our accrued post-retirement benefit liability and the service and interest components of the related net periodic benefit costs are calculated using an actuarial assumption regarding health care cost inflation. For measurement purposes, a 6.5%, 7.5%, 4.5% and 10.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017 for pre-65 medical, pre-65 drug, post-65 medical and post-65 drug, respectively. The health care cost trend rates are assumed to decline steadily to an ultimate rate of 4.5% by 2025 for pre-65 medical and by 2026 for pre-65 and post-65 drug. Post-65 medical trend is assumed to be 4.5% for all years into the future. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan.
The estimated rate of compensation increase used in our Retirement Plans is 4.5% and is based on recent trends for all non-union employees and the amounts we are contractually obligated for union employees.
In 2016, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension and other post-retirement benefits . This change, compared to the previous method, resulted in a decrease in the service cost and interest cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future periods. Historically, we estimated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. In 2016, we elected to utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. We believe the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding spot rates on the yield curve. We accounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively. The change in estimate decreased the service and interest components of net periodic benefit cost for pension and other post-retirement benefits in 2016 by approximately $2.9 million and $0.8 million , respectively.
The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2016 reported pension liability and our 2016 reported pension expense (in thousands):
 
 
Increase (Decrease)
Actuarial Assumption
 
Impact on Pension Liability
 
Impact on Pension Expense
Discount rate:
 
 
 
 
Increase 1%
 
$
(41,843
)
 
$
(3,601
)
Decrease 1%
 
51,463

 
4,343

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

 
(2,698
)
Decrease 1%
 
N/A

 
2,698

Compensation rate:
 
 
 
 
Increase 1%
 
6,615

 
1,241

Decrease 1%
 
(6,002
)
 
(1,106
)

29


The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2016 other post-retirement benefit obligations and our 2016 reported other post-retirement benefit expense (in thousands):
 
 
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%
 
$
(9,631
)
 
$
(1,329
)
 
$
(276
)
Decrease 1%
 
12,246

 
1,595

 
350

Healthcare cost trend rate:
 
 
 
 
 
 
Increase 1%
 
11,222

 
2,342

 
1,252

Decrease 1%
 
(8,951
)
 
(1,919
)
 
(973
)
Expected long-term rate of return on plan assets:
 
 
 
 
 
 
Increase 1%
 
N/A

 
(376
)
 
N/A

Decrease 1%
 
N/A

 
376

 
N/A

Tax Accruals
We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation or audit adjustments can materially affect amounts we recognize in our financial statements.
When appropriate, we record a valuation allowance against deferred tax assets to reflect that these tax assets may not be realized. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the results of operations and financial position of the Company. There were no valuation allowances for deferred tax assets as of December 31, 2016.
We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon settlement. The unrecognized tax benefits that do not meet the recognition and measurement standards were $2.6 million as of December 31, 2016.

Overview
The following is an overview of our results of operations for the years ended December 31, 2016 , 2015 and 2014 . Net income and basic earnings per share for the years ended December 31, 2016 , 2015 and 2014 are shown below:
 
 
Years Ended December 31,
 
2016
 
2015
 
2014
Net income (in thousands)
$
96,768

 
$
81,918

 
$
91,428

Basic earnings per share
2.39

 
2.03

 
2.27

Financial Effect of the PUCT Final Order
On August 25, 2016, the PUCT approved the Unopposed Settlement and issued its final order in Docket No.44941 (the "PUCT Final Order"), as proposed. See Part II, Item 8, "Financial Statements and Supplementary Data, Note C of Notes to Financial Statements."
For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, in the third quarter of 2016, the Company reported the cumulative effect of the PUCT Final Order, which related back to January 12, 2016.

30



The increase (decrease) on operations resulting from the PUCT Final Order is categorized in the following periods based on consumption (in thousands):
 
 
 
Three Months Ended
 
Twelve Months Ended
 
Category
 
 March 31, 2016
 
June 30, 2016
 
September 30, 2016
 
December 31, 2016
 
 December 31, 2016
 
Retail non-fuel base rate increase:
 
 
 
 
 
 
 
 
 
 
 
Relate back
 
$
4,782

 
$

 
$

 
$

 
$
4,782

 
Interim rates
 
457

 
10,417

 
15,138

 

 
26,012

 
Additional non-fuel base rate increase for Four Corners
 
708

 
867

 
1,328

 
853

 
3,756

 
Base rate increase
 

 

 

 
6,321

 
6,321

 
Retail non-fuel base rate increase, total
 
$
5,947

 
$
11,284

 
$
16,466

 
$
7,174

 
$
40,871

 
Miscellaneous service revenues
 
353

 
400

 
390

 
379

 
1,522

 
Revenue taxes
 
(19
)
 
(436
)
 
(643
)
 
(238
)
 
(1,336
)
 
Depreciation
 
2,491

 
2,510

 
2,412

 
2,849

 
10,262

 
Rate case expense
 

 

 
(600
)
 
(395
)
 
(995
)
 
AFUDC
 
(106
)
 
(87
)
 
(72
)
 
(52
)
 
(317
)
 
Pre-tax increase
 
$
8,666

 
$
13,671

 
$
17,953

 
$
9,717

 
$
50,007

 
Income tax expense (a)
 
4,104

 
5,677

 
7,221

 
5,714

 
22,716

 
After-tax increase
 
$
4,562

 
$
7,994

 
$
10,732

 
$
4,003

 
$
27,291

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
In the third quarter of 2016, the Company changed its accounting for state income taxes from the flow-through method to the normalization method in accordance with the PUCT Final Order and the NMPRC Final Order. The impact of the change was additional income tax expense of $5.1 million for the twelve months ended December 31, 2016.
 



31


The following table and accompanying explanations show the primary factors affecting the after-tax change in income between the calendar years ended 2016 and 2015 , 2015 and 2014 , and 2014 and 2013 (in thousands):
 

2016
 
2015
 
2014
 
Prior year December 31 net income
$
81,918

  
$
91,428

  
$
88,583

  
Changes (net of tax):
 
 
 
 
 
 
Increased (decreased) retail non-fuel base revenues
28,802

(a)
9,290

(b)
(3,533
)
(c)
Decreased (increased) depreciation and amortization
3,580

(d)
(4,214
)
(e)
(2,415
)
(f)
Increased (decreased) non-base revenue, net of energy expense
804

 
(5,370
)
(g)
3,779

(h)
Changes in the effective tax rate
(5,343
)
(i)
1,540

(j)
15

 
(Decreased) increased allowance for funds used during construction
(4,887
)
(k)
(4,953
)
(l)
6,157

(m)
Increased interest on long-term debt (net of capitalized interest)
(3,700
)
(n)
(4,516
)
(o)
(390
)
 
(Decreased) increased investment and interest income
(2,784
)
(p)
3,084

(q)
5,309

(r)
Increased taxes other than income taxes
(1,168
)
(s)
(641
)
 
(3,252
)
(t)
Other
(454
)
 
(3,730
)
 
(2,825
)
 
Current year December 31 net income
$
96,768

  
$
81,918

  
$
91,428

  
______________________ 
Footnotes reflect pre-tax amounts
(a)
Increased retail non-fuel base revenues primarily due to the recognition of $40.9 million related to the PUCT Final Order.
(b)
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.
(c)
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.
(d)
Depreciation and amortization decreased primarily due to (i) a reduction of approximately $10.9 million resulting from changes in depreciation rates approved in the PUCT Final Order and the NMPRC Final Order and (ii) the sale of the Company's interest in Four Corners. These decreases were partially offset by an increase in plant, primarily due to MPS Units 1 and 2 and the EOC each being placed in service in March 2015, and MPS Units 3 and 4 being placed in service in May 2016 and September 2016, respectively.
(e)
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.
(f)
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.
(g)
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.
(h)
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.
(i)
The effective tax rate increased due to the change to normalize state income taxes in accordance with the PUCT Final Order and the NMPRC Final Order.

32


(j)
The effective tax rate decreased due to a decrease in state income taxes and an increase in decommissioning income. These decreases were partially offset by a decrease in AEFUDC and the loss of the domestic production activities deduction in 2015.
(k)
AFUDC decreased due to lower balances of CWIP, primarily due to the MPS units and the EOC being placed in service in 2015 and 2016, and a reduction in the AFUDC rate effective January 2016 as a result of the PUCT Final Order.
(l)
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.
(m)
AFUDC increased, primarily due to higher balances of CWIP subject to AFUDC, reflecting construction work in progress on MPS and the EOC.
(n)
Interest on long-term debt increased, primarily due to the $150.0 million principal amount of senior notes issued in March 2016.
(o)
Interest on long-term debt increased, primarily due to the $150.0 million principal amount of senior notes issued in December 2014.
(p)
Investment and interest income decreased primarily due to lower realized gains on securities sold from the Company’s Palo Verde decommissioning trust in 2016 compared to 2015. The net gains reported in 2016 and 2015 are primarily the result of the Company's efforts to re-balance and further diversify its Palo Verde decommissioning trust fund investments.
(q)
Investment and interest income increased, primarily due to further diversification and re-balancing our Palo Verde decommissioning trust fund equity portfolio.
(r)
Investment and interest income increased, primarily due to increased gains on the sales of equity investments in our Palo Verde decommissioning trust funds.
(s)
Taxes other than income taxes increased primarily due to increased property tax rates and valuations in Texas as a result of MPS Units 1 and 2 and the EOC being placed in service during the first quarter of 2015 and increased billed revenues for Texas revenue related taxes. These increases were partially offset by decreased property taxes in Arizona due to lower property values.
(t)
Taxes other than income taxes increased, primarily due to higher property tax values and assessment rates. Additionally, in the first quarter of 2014, the Arizona tax district in which Palo Verde operates adjusted its 2013 property tax rate, resulting in an additional charge of $1.3 million.







33


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 2016, 2015 and 2014.
Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment mechanisms. Historically, a significant portion of fuel costs have been recovered through base rates in New Mexico. Effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel costs are no longer recovered through base rates. Beginning July 1, 2016, all fuel costs are recovered through a fuel adjustment mechanism. We record deferred fuel revenues for the difference between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. "Non-fuel base revenues" refers to our revenues from the sale of electricity excluding such fuel costs.
Retail non-fuel base revenue percentages by customer class are presented below:
 
    
 
Years Ended December 31,
 
2016
 
2015
 
2014
Residential
46
%
 
44
%
 
42
%
Commercial and industrial, small
32

 
33

 
34

Commercial and industrial, large
6

 
7

 
7

Sales to public authorities
16

 
16

 
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 78% of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structures in Texas and New Mexico reflect higher base rates during the peak summer season of May through October and lower base rates from November through April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base revenues derived during each quarter for the periods presented:
 
        
 
Years Ended December 31,
 
2016
 
2015
 
2014
January 1 to March 31
17
%
 
18
%
 
19
%
April 1 to June 30
25

 
26

 
27

July 1 to September 30
38

 
35

 
33

October 1 to December 31
20

 
21

 
21

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 2016, 2015 and 2014.  

        
 
2016
 
2015
 
2014
 
10-year
Average
Cooling degree days
2,811

 
2,839

 
2,671

 
2,732

Heating degree days
1,851

 
2,095

 
1,900

 
2,157



34


Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.5% and 1.4% in 2016 and 2015, respectively. See the tables presented on pages 37 and 38 which provide detail on the average number of retail customers and the related revenues and kWh sales.
Retail non-fuel base revenues . Retail non-fuel base revenues increased primarily due to the recognition of $40.9 million related to the PUCT Final Order. Excluding the $40.9 million PUCT Final Order impact, for the twelve months ended December 31, 2016, retail non-fuel base revenues increased $3.4 million, pre-tax, or 0.6%, compared to the twelve months ended December
31, 2015. This increase was primarily due to increased revenues from residential customers of $3.5 million due to a 1.3% increase in kWh sales and increased revenues from small commercial and industrial customers of $2.5 million due to a 0.8% increase in kWh sales. Increased kWh sales from residential customers and small commercial and industrial customers were driven by a 1.4% and 1.9% increase in the average number of customers, respectively, offset in part by milder weather during the twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015. Revenues decreased $2.4 million from large commercial and industrial customers during the twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015 due to a 3.0% decrease in kWh sales, due primarily to reduced demand by the steel manufacturing industry, and a decrease in surcharges billed to a large customer in 2016 compared to 2015. Revenues decreased $0.2 million from public authority customers reflecting a 0.8% decrease in kWh sales. Cooling degree days were relatively consistent with 2015 and were 2.9% over the 10-year average. Heating degree days decreased 11.6% in 2016, compared to 2015, and were 14.2% below the 10-year average.
Retail non-fuel base revenues increased $14.3 million, or 2.6%, for the twelve months ended December 31, 2015 when compared to the twelve months ended December 31, 2014. This increase includes an $11.9 million increase in revenues from residential customers and a $2.0 million increase in revenues from small commercial and industrial customers reflecting hotter summer weather and increases of 1.3% and 1.6%, respectively, in the average number of residential customers and small commercial and industrial customers. KWh sales to public authorities increased 1.5% while revenue declined by $0.8 million, primarily due to a military installation moving a portion of their load to an interruptible rate. Retail non-fuel revenues from large commercial and industrial customers increased $1.2 million due to a surcharge billed to a large customer. Cooling degree days increased 6.3% in 2015, when compared to the same period in the prior year, and were 5.3% over the 10-year average. Heating degree days increased 10.3% for 2015, compared to 2014, and were 3.6% below the 10-year average.
Fuel revenues . Fuel revenues consist of (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions and the FERC, (ii) deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers and (iii) prior to July 1, 2016, fuel costs recovered in base rates in New Mexico.
In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor based upon an approved formula at least four months after our last revision, except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over and under recoveries are defined as material when they exceed 4% of the previous twelve months' fuel costs. On April 15, 2015, we filed a request, which was assigned PUCT Docket No. 44633, to reduce our fixed fuel factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and was approved by the PUCT on May 20, 2015. On November 30, 2016, we filed a request, which was assigned PUCT Docket No. 46610, to increase our fixed fuel factor by approximately 28.8% to reflect increased fuel expenses primarily related to an increase in the price of natural gas used to generate power. The increase in the fixed fuel factor was effective on an interim basis January 3, 2017 and approved by the PUCT on January 10, 2017. On September 27, 2016, we filed an application with the PUCT, designated as PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 31, 2016.
In New Mexico, effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs will no longer be recovered through base rates, as it was historically, but will be completely recovered through the Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC"). Fuel and purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. The Company's request to reconcile its fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in the NMPRC Final Order.
In March 2015 and March 2016, $5.8 million and $1.6 million, respectively, were credited to customers through the applicable fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage.
We under-recovered fuel costs by $14.9 million in the twelve months ended December 31, 2016. We over-recovered fuel costs by $13.3 million and under-recovered $3.1 million in the twelve months ended December 31, 2015 and 2014, respectively. At December 31, 2016, we had a net fuel under-recovery balance of $10.9 million, including an under-recovery of $11.1 million in Texas offset by an over-recovery of $0.2 million in New Mexico.

35


Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. We have shared 100% of margins on non-arbitrage sales (as defined by the settlement in PUCT Docket No. 41852) and 50% of margins on arbitrage sales with our Texas customers since April 1, 2014. For the period April 1, 2014 through June 30, 2015, our total share of margins assignable to the Texas retail jurisdiction, on arbitrage and non-arbitrage off-system sales, could not exceed 10% of the total margins assignable to the Texas retail jurisdiction on all off-system sales. We are currently sharing 90% of off-system sales margins with our New Mexico customers, and 25% of our off-system sales margins with our sales for resale customer under the terms of their contract.
Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. Palo Verde's availability is an important factor in realizing these off-system sales margins.
The table below shows MWhs, sales revenue, fuel cost, total margins and retained margins made on off-system sales for the twelve months ended December 31, 2016 , 2015 and 2014 (in thousands, except for MWhs).

        
 
Years Ended December 31,
 
2016
 
2015
 
2014
MWh sales
1,927,508

 
2,500,947

 
2,609,769

Sales revenue
$
45,702

 
$
64,816

 
$
97,980

Fuel cost
$
38,933

 
$
52,406

 
$
74,716

Total margins
$
6,769

 
$
12,410

 
$
23,264

Retained margins
$
1,137

 
$
1,362

 
$
2,147


Off-system sales revenue decreased $19.1 million, or 29.5%, and the related retained margins decreased $0.2 million, or 16.5%, for the twelve months ended December 31, 2016 when compared to 2015 as a result of lower average market prices for power and a 22.9% decrease in MWh sales. Off-system sales revenues decreased $33.2 million, or 33.8%, and the related retained margins decreased $0.8 million, or 36.6%, for the twelve months ended December 31, 2015 when compared to 2014 as a result of lower average market prices for power and a 4.2% decrease in MWh sales.
 


36


Comparisons of kWh sales and operating revenues are shown below:  
 
 
 
 
 
Increase (Decrease)
 
 
Years Ended December 31:
2016
 
2015
 
Amount
 
Percent
 
 
kWh sales (in thousands):
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
Residential
2,805,789

 
2,771,138

 
34,651

 
1.3
 %
 
 
Commercial and industrial, small
2,403,447

 
2,384,514

 
18,933

 
0.8

 
 
Commercial and industrial, large
1,030,745

 
1,062,662

 
(31,917
)
 
(3.0
)
 
 
Sales to public authorities
1,572,510

 
1,585,568

 
(13,058
)
 
(0.8
)
 
 
Total retail sales
7,812,491

 
7,803,882

 
8,609

 
0.1

 
 
Wholesale:
 
 
 
 
 
 


 
 
Sales for resale
62,086

 
63,347

 
(1,261
)
 
(2.0
)
 
 
Off-system sales
1,927,508

 
2,500,947

 
(573,439
)
 
(22.9
)
 
 
Total wholesale sales
1,989,594

 
2,564,294

 
(574,700
)
 
(22.4
)
 
 
Total kWh sales
9,802,085

 
10,368,176

 
(566,091
)
 
(5.5
)
 
 
Operating revenues (in thousands):
 
 
 
 
 
 


 
 
Non-fuel base revenues:
 
 
 
 
 
 


 
 
Retail:
 
 
 
 
 
 


 
 
Residential
$
278,774

 
$
246,265

 
$
32,509

 
13.2
 %
 
 
Commercial and industrial, small
194,942

 
187,436

 
7,506

 
4.0

 
 
Commercial and industrial, large
39,070

 
40,411

 
(1,341
)
 
(3.3
)
 
 
Sales to public authorities
96,881

 
91,244

 
5,637

 
6.2

 
 
Total retail non-fuel base revenues (1)
609,667

 
565,356

 
44,311

 
7.8

 
 
Wholesale:
 
 
 
 
 
 


 
 
Sales for resale
2,407

 
2,455

 
(48
)
 
(2.0
)
 
 
Total non-fuel base revenues
612,074

 
567,811

 
44,263

 
7.8

 
 
Fuel revenues:
 
 
 
 
 
 


 
 
Recovered from customers during the period
148,397

 
127,765

 
20,632

 
16.1

 
 
Under (over) collection of fuel (2)
14,893

 
(13,342
)
 
28,235

 
-

 
 
New Mexico fuel in base rates
33,279

 
72,129

 
(38,850
)
 
(53.9
)
 
 
Total fuel revenues (3)
196,569

 
186,552

 
10,017

 
5.4

 
 
Off-system sales:
 
 
 
 
 
 


 
 
Fuel cost
38,933

 
52,406

 
(13,473
)
 
(25.7
)
 
 
Shared margins
5,632

 
11,048

 
(5,416
)
 
(49.0
)
 
 
Retained margins
1,137

 
1,362

 
(225
)
 
(16.5
)
 
 
Total off-system sales
45,702

 
64,816

 
(19,114
)
 
(29.5
)
 
 
 
 
 
 
 
 
 


 
 
Other (4) (5)
32,591

 
30,690

 
1,901

 
6.2

 
 
Total operating revenues
$
886,936