Company Quick10K Filing
Quick10K
El Paso Electric
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$59.77 41 $2,440
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2018-12-26 Officers, Other Events, Exhibits
8-K 2018-11-01 Earnings, Exhibits
8-K 2018-09-13 Enter Agreement, Leave Agreement, Off-BS Arrangement, Exhibits
8-K 2018-08-02 Earnings, Exhibits
8-K 2018-06-28 Off-BS Arrangement, Exhibits
8-K 2018-05-24 Shareholder Vote, Other Events
8-K 2018-05-03 Earnings, Exhibits
8-K 2018-04-05 Officers
8-K 2018-02-27 Earnings, Exhibits
8-K 2018-01-31 Officers, Exhibits
CL Colgate Palmolive 59,360
NUE Nucor 17,740
HOG Harley Davidson 6,480
AU Anglogold Ashanti 5,370
SHEN Shenandoah Telecommunications 2,170
COT Cott 2,010
SYX Systemax 863
ELVT Elevate Credit 198
BTHE Boston Therapeutics 0
CAPS Capstone Therapeutics 0
EE 2018-12-31
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers of The Registrant and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
EX-10.28-01 eeex_1028-012018123110k.htm
EX-23.01 eeex_23012018123110k.htm
EX-24.02 eeex_24022018123110k.htm
EX-31.01 eeex_31012018123110k.htm
EX-32.01 eeex_32012018123110k.htm

El Paso Electric Earnings 2018-12-31

EE 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 a201810-k.htm FORM 10-K Document
 
 
 
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, 2018
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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES  x    NO  ¨ 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
x
Accelerated filer
 
o
Non-accelerated filer
 
o
Smaller reporting company
 
o
 
 
 
Emerging growth company
 
o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    YES  ¨    NO  x
As of June 30, 2018, the aggregate market value of the voting stock held by non-affiliates of the registrant was $2,196,858,522 (based on the closing price as quoted on the New York Stock Exchange on that date).
As of January 31, 2019, there were 40,740,080 shares of the Company’s common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement for the 2019 annual meeting of its shareholders are incorporated by reference into Part III of this report.

 
 
 


DEFINITIONS
The following abbreviations, acronyms or defined terms used in this report are defined below:
 
Abbreviations, Acronyms or Defined Terms
  
Terms
 
 
 
A&G
 
Administrative and general
ABFUDC
 
Allowance for Borrowed Funds Used During Construction
AEFUDC
 
Allowance for Equity Funds Used During Construction
AFUDC
 
Allowance for Funds Used During Construction
ANPP Participation Agreement
  
Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended
AOCI
 
Accumulated Other Comprehensive Income
APS
  
Arizona Public Service Company
ARO
 
Asset Retirement Obligations
ASU
  
Accounting Standards Update
Company
  
El Paso Electric Company
CWIP
 
Construction Work In Progress
Copper
 
The Company's Copper Power Station
D.C. Circuit
 
U.S. Court of Appeals for the District of Columbia Circuit
DOE
  
U.S. Department of Energy
El Paso
  
City of El Paso, Texas
EOC
 
The Company's Eastside Operations Center
EPA
 
U.S. Environmental Protection Agency
Exchange Act
 
The Securities Exchange Act of 1934, as amended
FASB
  
Financial Accounting Standards Board
FERC
  
Federal Energy Regulatory Commission
Fort Bliss
  
Fort Bliss, the U.S. Army post next to El Paso, Texas
Four Corners
 
Four Corners Generating Station
FPPCAC
 
New Mexico Fuel and Purchased Power Cost Adjustment Clause
GAAP
 
U.S. Generally Accepted Accounting Principles
GHG
 
Greenhouse Gas
HAFB
 
Holloman Air Force Base
kW
  
Kilowatt(s)
kWh
  
Kilowatt-hour(s)
Las Cruces
  
City of Las Cruces, New Mexico
MPS
 
The Company's Montana Power Station
MW
  
Megawatt(s)
MWh
  
Megawatt-hour(s)
NAAQS
 
National Ambient Air Quality Standards
NAV
 
Net Asset Value
NDT
 
The Company's Palo Verde nuclear decommissioning trust funds
Net dependable generating capability
  
The maximum load net of plant operating requirements that a generating plant can supply under specified conditions for a given time interval, without exceeding approved limits of temperature and stress
Newman
 
The Company's Newman Power Station
NMPRC
  
New Mexico Public Regulation Commission
NMPRC Final Order
 
NMPRC Final Order in Case No. 15-00127-UT
NOL
 
Net Operating Losses

               
 
( i)
 


Abbreviations, Acronyms or Defined Terms
  
Terms
NOL carryforwards
 
Net Operating Loss carryforwards
NRC
  
Nuclear Regulatory Commission
OPEB Plan
 
The Company's other post-retirement benefits plan, including health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only
O&M
 
Operations and maintenance
Palo Verde
  
Palo Verde Generating Station
Palo Verde Participants
  
Those utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement
PCBs
 
Pollution Control Bonds
PUCT
  
Public Utility Commission of Texas
PURA
 
Public Utility Regulatory Act
RCF
 
The Company's Revolving Credit Facility
Retirement Plan
 
The Company's Retirement Income Plan
RGEC
  
Rio Grande Electric Cooperative
RGRT
  
Rio Grande Resources Trust II
Rio Grande
 
The Company's Rio Grande Power Station
RPS
 
Renewable Portfolio Standard
SAB 118
 
SEC Staff Accounting Bulletin No. 118
SEC
 
U.S. Securities and Exchange Commission
Securities Act
 
The Securities Act of 1933, as amended
Standard Contract
 
Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste
TCJA
 
The federal legislation commonly referred to as the Tax Cuts and Jobs Act of 2017
U.S.
 
United States
White Sands
 
White Sands Missile Range
2016 PUCT Final Order
  
PUCT Final Order in Docket No. 44941
2016 Study
 
2016 Palo Verde Decommissioning Study
2017 All Source RFP
 
2017 All Source Request for Proposals for Electric Power Supply and Load Management Resources
2017 PUCT Final Order
 
PUCT Final Order in Docket No. 46831
2019 Proxy Statement
 
Proxy statement for the Company's 2019 Annual Meeting of Shareholders
2019 TCRF rate filing
 
Transmission Cost Recovery Factor rate filing in PUCT Docket No. 49148
 


               
 
( ii)
 


TABLE OF CONTENTS
 
 
 
 
Item
Description
Page
 
 
1

1A

1B

2

3

4

 
 
 
 
 
 
 
 
5

6

7

7A

8

9

9A

9B

 
 
 
 
 
10

11

12

13

14

 
 
 
 
 
15

16

 


               
 
( iii)
 


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

               
 
( iv)
 


unscheduled outages of generating units including outages at Palo Verde,
changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging competing services and technologies, including distributed generation and battery storage,
individual customer groups, including distributed generation customers, may not pay their full cost of service, and other customers may or may not be required to pay the difference,
changes in, and the assumptions used for, pension and other post-retirement and post-employment benefit liability calculations, as well as actual and assumed investment returns on pension plan and other post-retirement plan assets,
the impact of changing cost escalation and other assumptions on the Company's nuclear decommissioning liability for Palo Verde, as well as actual and assumed investment returns on assets in the Company's Palo Verde nuclear decommissioning trust funds ("NDT"),
disruptions in the Company's transmission and distribution systems, and in particular the lines that deliver power from its remote generating facilities,
the sufficiency of the Company's insurance coverage, including availability, cost, coverage and terms,
electric utility deregulation or re-regulation,
regulated and competitive markets,
ongoing municipal, state and federal activities,
cuts in military spending or prolonged shutdowns of the federal government that reduce demand for the Company's services from military and governmental customers,
political, legislative, judicial and regulatory developments,
homeland security considerations, including those associated with the United States ("U.S.")/Mexico border region and the energy industry,
changes in environmental laws and regulations and the enforcement or interpretation thereof, including those related to air, water or greenhouse gas ("GHG") emissions or other environmental matters,
economic, commercial bank, financial and capital market conditions,
increases in cost of capital,
the impact of changes in interest rates or rates of inflation,
actions by credit rating agencies,
changes in accounting requirements and other accounting matters,
changing weather trends and the impact of severe weather conditions,
possible physical or cyber attacks, intrusions or other catastrophic events,
the impact of lawsuits filed against the Company,
Texas, New Mexico and electric industry utility service reliability standards and service requirements,
uranium, natural gas, oil and wholesale electricity prices and availability,
possible income tax and interest payments as a result of audit adjustments proposed by the U.S. Internal Revenue Service or state taxing authorities,
the impact of recent changes to U.S. tax laws,
the impact of international trade and tariff negotiations,
the impact of U.S. health care reform legislation,
the effectiveness of the Company's risk management activities,
the Company's ability to successfully renegotiate its collective bargaining agreement,
loss of key personnel, the Company's ability to recruit and retain qualified employees and the Company's ability to successfully implement succession planning, and

               
 
( v)
 


other circumstances affecting anticipated operations, sales and costs.
These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this Annual Report on Form 10-K under the headings "Risk Factors" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations –Summary of Critical Accounting Policies and Estimates" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations –Liquidity and Capital Resources." This Annual Report on Form 10-K should be read in its entirety. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. Any forward-looking statement speaks only as of the date such statement was made, and the Company is not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made, except as required by applicable laws or regulations.

               
 
( vi)
 


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 capacity of approximately 2,085 megawatts ("MW"). For the year ended December 31, 2018, the Company’s energy sources consisted of approximately 44% nuclear fuel, 44% natural gas, 12% purchased power and less than 1% generated by Company-owned solar photovoltaic panels. As of December 31, 2018, the Company had power purchase agreements for 107 MW from solar photovoltaic generation facilities and intends to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. See "Energy Sources – Purchased Power."
The Company serves approximately 425,000 residential, commercial, industrial, public authority and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 64% and 11%, respectively, of the Company’s retail revenues for the year ended December 31, 2018). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public authority and other large retail customers of the Company include U.S. military installations, such as Fort Bliss in Texas and White Sands Missile Range ("White Sands") and Holloman Air Force Base ("HAFB") in New Mexico, an oil refinery, several medical centers, two large universities and a steel production facility.
The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone: 915-543-5711). The Company was incorporated in Texas in 1901. As of January 31, 2019, the Company had approximately 1,100 employees, 37% of whom are covered by a collective bargaining agreement.
The Company makes available free of charge through its website, www.epelectric.com, its Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statement and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the U.S. Securities and Exchange Commission ("SEC"). In addition, copies of this Annual Report on Form 10-K will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov. The information on the Company's website is not incorporated by reference into this Annual Report on Form 10-K.
Facilities
As of December 31, 2018, the Company’s net dependable generating capability of approximately 2,085 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 County, Texas
Copper Power Station
 
Natural Gas
 
64

 
100
%
 
El Paso County, Texas
Renewables**
 
Solar
 
6

 
100
%
 
Culberson County and El Paso County, Texas; Doña Ana County and Otero County, New Mexico
Total
 
 
 
2,085

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


1


Palo Verde
The Company owns an interest, along with six other utilities, in the three nuclear generating units and common facilities ("Common Facilities") at Palo Verde. Arizona Public Service Company ("APS") serves as operating agent for Palo Verde, and under the Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended ("ANPP Participation Agreement"), the Company has limited ability to influence operations and costs at Palo Verde.
Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the U.S. Nuclear Regulatory Commission ("NRC"). The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 2047, respectively.
Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses. In 2017, the Palo Verde Participants approved the 2016 Palo Verde decommissioning study ("2016 Study"), which estimated that the Company must fund approximately $432.8 million (stated in 2016 dollars) to cover its share of decommissioning costs. At December 31, 2018, the Company's decommissioning trust fund had a balance of $276.9 million. Although the 2016 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change.
Spent Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987, the U.S. Department of Energy ("DOE") is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste ("Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. Pursuant to the terms of the August 18, 2014 settlement agreement, and as amended with the DOE, APS files annual claims for the period July 1 of the then-previous year to June 30 of the then-current year on behalf of itself and those utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde based upon the ANPP Participation Agreement dated August 23, 1973. The settlement agreement, as amended, provides APS with a method for submitting claims and receiving recovery for costs incurred through December 31, 2016, which has been extended to December 31, 2019. The Company's share of costs recovered in 2018, 2017, and 2016, respectively are presented below (in thousands):
Costs Recovery Period
 
Amount Refunded
 
Amount Credited to Customers through Fuel Adjustment Clauses
 
Period Credited to Customers
 
 
 
 
 
 
 
July 2016 - June 2017
 
$
1,413

 
$
1,121

 
March 2018
July 2015 - June 2016
 
1,779

 
1,432

 
March 2017
July 2014 - June 2015
 
1,884

 
1,581

 
March 2016
On October 31, 2018, APS filed a $10.2 million claim for the period July 1, 2017 through June 30, 2018. The Company's share of this claim is approximately $1.6 million. This claim is pending DOE review. The majority of the reimbursement received by the Company is expected to be credited to customers through the applicable fuel adjustment clauses.
DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations by designing, licensing, constructing and operating a permanent geologic repository in Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE's authority to withdraw the Yucca Mountain construction authorization application and NRC’s cessation of its review of the Yucca Mountain construction authorization application. The cases have been consolidated into one matter at the U.S. Court of Appeals for the

2


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

3


fuel adjustment clauses. In June 2012, the D.C. Circuit held that the DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the Secretary of the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of the DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the Secretary of the DOE to notify Congress of his intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators, as he is required to do pursuant to the NWPA and the court’s order. On January 3, 2014, the Secretary of the DOE notified Congress of his intention to suspend collection of the one-mill fee, subject to Congress’ disapproval and on May 16, 2014, the DOE notified all commercial nuclear power plant operators, effective May 16, 2014, the one-mill fee was suspended. Electricity generated at Palo Verde and sold on or after May 16, 2014 is no longer subjected to the one-mill fee.
NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. The NRC regulates the operation of all commercial nuclear power reactors in the U.S., including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee's safety performance. Following the March 11, 2011 earthquake and tsunami in Japan, the NRC established a task force to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system. On March 12, 2012, the NRC issued the first regulatory requirements based on the recommendations of the NRC's Near Term Task Force. With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants and (2) enhancement of spent fuel pool instrumentation.
The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Palo Verde has met the NRC's imposed deadlines for the installation of equipment to address these requirements. Palo Verde has spent approximately $125.4 million (the Company's share is $19.8 million) on capital enhancements related to these requirements as of December 31, 2018.
Liability and Insurance Matters. The Palo Verde Participants have insurance for public liability resulting from nuclear energy hazards, covered by primary liability insurance provided by commercial insurance carriers and an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis up to $62.1 million, with an annual payment limitation of approximately $9.7 million. The Palo Verde Participants also maintain $2.8 billion of "all risk" nuclear property insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage limit is $2.3 billion. In addition, the Company has secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo Verde.
Fossil-Fueled Plants
The Company owns the Newman Power Station ("Newman"), which consists of three conventional steam-electric generating units and two combined cycle generating units. The station operates primarily on natural gas but the conventional steam-electric generating units can also operate on fuel oil.
The Company owns the Rio Grande Power Station ("Rio Grande"), which consists of two conventional steam-electric generating units and one aeroderivative unit that operates on natural gas. Rio Grande Unit 6 with net capacity of 42.5 MW, was initially placed in inactive reserve status in 2015, and has been activated as needed.  
The Company owns the Montana Power Station ("MPS"), which consists of four aeroderivative generating units that operate on natural gas. The units can also operate on fuel oil.
The Company owns the Copper Power Station ("Copper"), which consists of a natural gas combustion turbine used primarily to meet peak demand.
Prior to July 6, 2016, the Company owned a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners"). The Company shared power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. On July 6, 2016, the Company sold its interests in Four Corners for $32.0 million to 4C Acquisition, LLC, an affiliate of APS ("APS's affiliate"), and Pinnacle West Capital Corporation ("Pinnacle West"), the parent company of APS and APS's affiliate. No significant gain or loss was recorded for this sale. APS's affiliate assumed responsibility

4


for all Four Corners capital expenditures made after July 6, 2016, which assumption is guaranteed by Pinnacle West. In addition, APS's affiliate will indemnify the Company against certain liabilities and costs related to the future operation of Four Corners, which indemnification is guaranteed by Pinnacle West. See Part II, Item 8, Financial Statements and Supplementary Data, Note D and Note F of Notes to Financial Statements for further discussions.
Solar Photovoltaic Facilities
The Company’s Texas Community solar facility, a 3 MW utility-scale solar plant located at MPS, and the El Paso Electric Holloman Atlas Solar Array, a 5 MW utility-scale solar plant located on HAFB, began commercial operations on May 31, 2017, and October 18, 2018, respectively. The Company also owns six other solar photovoltaic facilities with a total capacity of 0.2 MW.
Transmission and Distribution Lines and Agreements
The Company owns, or has significant ownership interests in, four 345 kilovolt ("kV") transmission lines in New Mexico and Arizona and three 500 kV lines in Arizona. These lines enable the Company to deliver its energy entitlements from its remote generation at Palo Verde to its service area (pursuant to various transmission and power exchange agreements to which the Company is a party). The Company also owns the transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. Pursuant to standards established by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, the Company operates its transmission system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service.
In addition to the transmission and distribution lines within our service territory, the Company's transmission network and associated substations include the following:
Line
 
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's ("PNM") West Mesa Substation near Albuquerque, New Mexico, to the Company's Arroyo Substation near Las Cruces, New Mexico.
(3)
Runs from TEP's Greenlee Substation near Duncan, Arizona to Newman.
(4)
Runs from the Company's and PNM's high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico.
(5)
Represents two 45-mile, 500 kV lines running from Palo Verde to the Westwing Substation located northwest of Phoenix near Peoria, Arizona.
(6)
Runs from Palo Verde to the Jojoba Substation near Gila Bend, Arizona, then to the Kyrene Substation near Tempe, Arizona.

5


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

In March 2017, the Company entered into a Compliance Agreement ("Compliance Agreement") with the Texas Commission on Environmental Quality under the Texas Environmental, Health and Safety Audit Privilege Act to address certain water and waste compliance issues associated with the integrity of the synthetic liner of the evaporation pond at Newman. The Company has initiated a capital project to extend the life of evaporation pond and in doing so will complete its obligation of the Compliance Agreement. The Compliance Agreement remains in effect.
Air Emissions. The U.S. Clean Air Act ("CAA"), associated regulations and comparable state and local laws and regulations relating to air emissions impose, among other obligations, limitations on pollutants generated during the operations of the Company's facilities and assets, including sulfur dioxide, particulate matter and nitrogen oxides.
National Ambient Air Quality Standards ("NAAQS"). Under the CAA, the U.S Environmental Protection Agency ("EPA") sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including particulate matter, nitrogen oxide, carbon monoxide, ozone and sulfur dioxide. On October 1, 2015, the EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion ("ppb") to 70 ppb. The EPA published the Final Rule on June 4, 2018, designating El Paso County, Texas, as "attainment/unclassifiable" under the 2015 ozone NAAQS and designating a section of southern Doña Ana County, New Mexico, as "nonattainment." In August, several petitions for review of the Final Rule were filed in the D.C. Circuit. One of these petitions, filed by the City of Sunland Park, New Mexico, specifically challenges the "attainment/unclassifiable" designation of El Paso County, Texas. The Company and other intervenors filed and were granted motions to intervene in the challenges to EPA's 2015 ozone NAAQS designations. A briefing schedule extending through July 2019 has been established for the case.
States, including New Mexico, that contain any areas designated as nonattainment are required to complete development of implementation plans in the 2020-2021 timeframe. Most nonattainment areas are expected to have until 2020 or 2023 to meet the primary (health) standard, with the exact attainment date varying based on the ozone level in the area. The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the NAAQS, individually or in the aggregate, could have a material impact on its operations and financial results.
Other Laws and Regulations and Risks. The Company sold its interest in Four Corners to APS's affiliate on July 6, 2016 at the expiration of the 50-year participation agreement. As of the closing date of the sale, the Company’s environmental liabilities associated with Four Corners were limited to conditions that existed at the time of the sale and further limited to the portion thereof for which the Company would have been financially responsible if Four Corners had fully ceased operation on July 6, 2016. Pursuant to the terms of the asset purchase agreement ("Purchase and Sale Agreement"), neither APS's affiliate nor APS assumed the Company's pre-closing obligations under environmental laws with respect to its interest in Four Corners. The Company may be subject to certain future claims under environmental laws and regulations as a former owner of Four Corners. The extent of such claims, if any, cannot be predicted with certainty.
Climate Change. There has been a wide-ranging policy debate, at the local, state, national and international levels, regarding the impact of GHG and possible means for their regulation. Efforts continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In April 2016, the United States signed the Paris Agreement, which requires countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. In August 2017, the United States formally documented to the United Nations its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 2020. At the state level, several states have already adopted measures requiring GHG emissions to be reduced within state boundaries. For example, the governor of New Mexico signed an executive order in January 2019 that supports the Paris Agreement and includes a goal of reducing statewide GHG emissions by at least 45% by 2030. The executive order also creates a Climate Change Task Force to evaluate and develop regulatory strategies to reach the 45% reduction goal. Although the Company cannot currently determine the effect of potential regulatory strategies that may be

6


suggested by the New Mexico Climate Change Task Force, if implemented, they could be material to the Company's business, reputation, financial condition or results of operations.
The federal government has considered, proposed and/or finalized legislation or regulations limiting GHG emissions, including carbon dioxide. In particular, the U.S. Congress has considered legislation to restrict or regulate GHG emissions. In October 2015, the EPA published a rule establishing guidelines for states to regulate carbon dioxide emissions from existing power plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. On August 31, 2018, the EPA published a proposal to replace the CPP called the Affordable Clean Energy ("ACE") rule. The ACE rule has not yet been finalized. At this time the Company cannot determine the impact that the CPP, the ACE rule, and related proposals and legal challenges may have on our financial position, results of operations or cash flows.
A significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes that its GHG emissions are low relative to electric power companies who rely more on coal-fired generation. Current and future legislation and regulation of GHG or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduce demand for the power the Company generates, and/or require the Company to purchase rights to emit GHG, any of which could be material to the Company's business, reputation, financial condition or results of operations.
Climate change also has potential physical effects that could be relevant to the Company's business. Climate change could affect the Company's service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment. The Company believes that material effects on the Company's business or results of operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Given the significant uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is not possible to meaningfully quantify the costs of these potential impacts at present.
Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice, on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce sulfur dioxide, nitrogen oxides, and particulate matter, and that APS failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. District Court for the District of New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S. District Court entered the CAA Settlement Agreement. The agreement imposes a total civil penalty payable by the co-owners of Four Corners collectively in the amount of $1.5 million, and it requires the co-owners to pay $6.7 million for environmental mitigation projects. At December 31, 2018, the Company has accrued its remaining unpaid share of approximately $0.2 million related to this matter.

7


Construction Program
Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems, the cost of capital improvements and replacements at Palo Verde and other generating facilities, and other property and equipment. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system and to replace retiring plants. After evaluation of the competitive 2017 All Source Request for Proposals for Electric Power Supply and Load Management Resources (“2017 All Source RFP”), the winning bids include the construction of a 226 MW natural gas combustion turbine generating unit at Newman in El Paso with an anticipated operational date in 2023. The costs of the new generating unit are included in the table below. The winning bids also included purchased power agreements for 200 MW of utility scale solar resources and 100 MW of battery storage, which are not included in the construction program. The selected proposals are subject to the execution of contracts following negotiations with the winning bidders, obtaining the applicable environmental and construction related permits, and obtaining necessary approvals by the Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC").
The Company’s estimated cash construction costs for 2019 through 2023 are approximately $1.3 billion. Actual costs may vary from the construction program estimates shown. Such estimates are under continuous review and subject to ongoing adjustment and are updated periodically to reflect changed conditions.

    
By Year (1)(2)(3)
(estimates in millions)
 
By Function
(estimates in millions)
2019
$
249

 
Production (1)(2)
$
450

2020
224

 
Transmission
167

2021
266

 
Distribution (3)
518

2022
278

 
General
161

2023
279

 
 
 
Total
$
1,296

 
Total
$
1,296

__________________________
(1)
Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel."
(2)
Estimated production costs consist of:    
a.
$185 million for new generating capacity, including:
i.
$143 million of construction costs from 2019 through 2023 for a 226 MW combustion turbine generating unit at Newman with an anticipated operational date in 2023 as a result of the 2017 All Source RFP.
ii.
$42 million of initial construction costs from 2019 through 2023 for a 320 MW combined cycle generating unit to be completed in 2027.
b.
$265 million of other generation costs, including $185 million for Palo Verde.
(3)
Estimated distribution costs include:
a.
$85 million of initial project costs for Advanced Metering Infrastructure ("AMI"), including deployment of the back-office systems and meters. Legislative proposals regarding the clarification of the regulatory process to implement AMI are anticipated during the Texas legislative session that convened in January 2019. With legislative clarification, the Company would then have the opportunity to request regulatory approval for the deployment of AMI.





8


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,
 
2018
 
2017
 
2016
Power Source
(percentage of total kWh energy mix)
Nuclear
44
%
 
49
%
 
49
%
Natural gas
44
%
 
36
%
 
34
%
Coal
%
 
%
 
2
%
Purchased power
12
%
 
15
%
 
15
%
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 PUCT and the NMPRC. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further discussion on Texas and New Mexico Regulatory Matters.
Nuclear Fuel
The nuclear fuel cycle for Palo Verde consists of the following stages:  the mining and milling of uranium ore to produce uranium concentrates, the conversion of the uranium concentrates to uranium hexafluoride ("conversion services"), the enrichment of uranium hexafluoride ("enrichment services"), the fabrication of fuel assemblies ("fabrication services"), the utilization of the fuel assemblies in the reactors, and the storage and disposal of the spent fuel. 
Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Palo Verde Participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The Palo Verde Participants have contracted for 100% of Palo Verde's requirements for uranium concentrates through 2025 and 15% of its requirements through 2028. The participants have contracted for 100% of Palo Verde's requirement for conversion services through 2025 and 40% of its requirements through 2028. The participants have also contracted for 100% of Palo Verde's requirement for enrichment services through 2021 and 90% of its requirement for 2022, and 80% for 2023 through 2026 and all of Palo Verde's requirement for fuel assembly fabrication services through 2027.
Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust II ("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. As of December 31, 2018, RGRT has $110 million aggregate principal amount of senior notes due 2020 and 2025. On June 28, 2018, RGRT completed the sale of $65 million aggregate principal amount of senior notes due August 15, 2025. The Company guarantees the payment of principal and interest on the RGRT senior notes. The proceeds from the sale of the RGRT senior notes were used by RGRT to repay amounts borrowed under the then-existing revolving credit facility and enable future nuclear fuel financing requirements of RGRT to be met with a combination of the senior notes and amounts borrowed under the Company's Revolving Credit Facility ("RCF").
Natural Gas
The Company manages its natural gas requirements through a combination of a long-term (greater than a year) supply contract, several medium-term (greater than a month but less than one year) supply contracts and spot or short-term (daily to a month) market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. Medium-term and spot agreements are either fixed priced and/or index priced depending on the market. Through March 2018, the Company’s natural gas requirements at Newman, Rio Grande and MPS were met with short-term, medium-term and long-term natural gas purchases from various suppliers; thereafter, there were only short-term and medium term natural gas purchases, and this practice is expected to continue in 2019. Interstate gas is delivered under a base firm transportation contract. The Company has expanded its firm interstate transportation contract to include MPS. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for Newman, Rio Grande and MPS. The Company will continue to evaluate the availability of short-term natural gas supplies versus medium and long-term supplies to maintain a reliable and economical supply for its local generating stations.

9


Natural gas for Newman and Copper was also delivered pursuant to a long-term intrastate natural gas contract for firm transportation that became effective October 1, 2009 and continued through March 31, 2018. Beginning April 1, 2018, intrastate natural gas reservation and storage for Newman and Copper has been provided through new contracts with ONEOK WesTex Transmission, LLC and ONEOK Texas Gas Storage, LLC, respectively, that continue through March 31, 2028. It is anticipated that deliveries of intrastate natural gas to MPS may begin in the first quarter of 2019. Under this new contract, intrastate gas supply will be sourced in the same manner as interstate gas through a variety of medium and short-term purchase contracts.
Purchased Power
To supplement its own generation and operating reserve requirements, and to meet its Renewable Portfolio Standard ("RPS") requirements, the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the Company’s resource needs, the economics of the transactions and specific RPS requirements.
The Company has a firm 100 MW Power Purchase and Sale Agreement ("Power Purchase and Sale Agreement") with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport"), pursuant to which Freeport will deliver energy to the Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and the Company will deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to the contracted MW amount at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. The Power Purchase and Sale Agreement was approved by the Federal Energy Regulatory Commission ("FERC") and will continue through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold thereunder. The parties have agreed to increase the amount up to 125 MW through December 2021.
The Company has entered into several power purchase agreements to help meet its RPS requirements. Specifically, the Company has a 25-year power purchase agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico, which began commercial operation in July 2011. In June 2015, the Company entered into a consent agreement with Hatch Solar Energy Center I, LLC to provide for additional or replacement photovoltaic modules. The Company also entered into a 20-year contract with Solar Roadrunner, LLC, a subsidiary of Global Infrastructure Partners, (formerly known as NRG Solar Roadrunner LLC) for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico, which began commercial operation in August 2011. In addition, the Company has 25-year power purchase agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunE EPE1, LLC (10 MW) and SunE EPE2, LLC (12 MW), which began commercial operation in June 2012 and May 2012, respectively. In September 2017, Longroad Solar Portfolio Holdings, LLC purchased SunE EPE1, LLC, and in October 2017, Silicon Ranch Corporation purchased SunE EPE2, LLC with the Company's consent per the terms of both power purchase agreements.
Furthermore, the Company has a 20-year power purchase agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico which began commercial operation in May 2014. Finally, the Company has a 30-year power purchase agreement with Newman Solar LLC to purchase the total output, which is approximately 10 MW, from a solar photovoltaic generation plant on land subleased from the Company in proximity to Newman. This solar project began commercial operation in December 2014.
Other purchases of shorter duration were made during 2018 to supplement the Company's generation resources during planned and unplanned outages, for economic reasons and to supply off-system sales.
The Company recently concluded and announced its selection of resources from its 2017 All Source RFP. In addition to conventional natural gas generation, the Company will be initiating contract negotiations during 2019 for power purchase agreements from both solar and battery storage resources. Furthermore, the Company will pursue negotiations for possible additional solar and wind purchase power if there are potential energy cost savings.


10


Operating Statistics
 
Years Ended December 31,
 
2018
 
2017
 
2016
Operating revenues (in thousands):
 
 
 
 
 
Non-fuel base revenues:
 
 
 
 
 
Retail:
 
 
 
 
 
Residential
$
297,597

 
$
287,884

 
$
278,774

Commercial and industrial, small
194,341

 
198,799

 
194,942

Commercial and industrial, large
34,920

 
38,403

 
39,070

Sales to public authorities
95,460

 
97,890

 
96,881

Total retail base revenues
622,318

 
622,976

 
609,667

Wholesale:
 
 
 
 
 
Sales for resale - full requirement customer
2,780

 
2,730

 
2,407

Total non-fuel base revenues
625,098

 
625,706

 
612,074

Fuel revenues:
 
 
 
 
 
Recovered from customers during the period
156,493

 
218,380

 
148,397

Under (over) collection of fuel
(4,736
)
 
(17,133
)
 
14,893

New Mexico fuel in base rates

 

 
33,279

Total fuel revenues
151,757

 
201,247

 
196,569

Off-system sales
86,418

 
58,986

 
45,702

Wheeling revenues
19,026

 
18,114

 
21,966

Energy efficiency cost recovery
8,888

 

 

Miscellaneous
8,188

 
8,229

 
7,034

Total revenues from customers
899,375

 
912,282

 
883,345

Other
4,228

 
4,515

 
3,591

Total operating revenues
$
903,603

 
$
916,797

 
$
886,936

Number of customers (end of year) (1):
 
 
 
 
 
Residential
376,651

 
370,054

 
363,987

Commercial and industrial, small
42,141

 
42,291

 
41,741

Commercial and industrial, large
48

 
48

 
49

Other
6,170

 
5,500

 
5,285

Total
425,010

 
417,893

 
411,062

Average annual kWh use per residential customer
7,988

 
7,671

 
7,748

Energy supplied, net, kWh (in thousands):
 
 
 
 
 
Generated
9,943,721

 
8,950,875

 
8,820,006

Purchased and interchanged
1,355,309

 
1,540,841

 
1,552,251

Total
11,299,030

 
10,491,716

 
10,372,257

Energy sales, kWh (in thousands):
 
 
 
 
 
Retail:
 
 
 
 
 
Residential
2,988,695

 
2,823,260

 
2,805,789

Commercial and industrial, small
2,431,920

 
2,410,710

 
2,403,447

Commercial and industrial, large
1,050,834

 
1,045,319

 
1,030,745

Sales to public authorities
1,563,227

 
1,564,670

 
1,572,510

Total retail
8,034,676

 
7,843,959

 
7,812,491

Wholesale:
 
 
 
 
 
Sales for resale - full requirement customer
58,991

 
62,887

 
62,086

Off-system sales
2,687,961

 
2,042,884

 
1,927,508

Total wholesale
2,746,952

 
2,105,771

 
1,989,594

Total energy sales
10,781,628

 
9,949,730

 
9,802,085

Losses and Company use
517,402

 
541,986

 
570,172

Total
11,299,030

 
10,491,716

 
10,372,257

Native system:
 
 
 
 
 
Peak load, kW
1,929,000

 
1,935,000

 
1,892,000

Net dependable generating capability for peak, kW
2,085,000

 
2,082,000

 
2,080,000

Total system:
 
 
 
 
 
Peak load, kW (2)
2,006,000

 
1,982,000

 
2,027,000

Net dependable generating capability for peak, kW
2,085,000

 
2,082,000

 
2,080,000

___________________________
(1)
The number of retail customers presented is based on the number of service locations.
(2)
Includes spot sales and net losses of 77,000 kilowatts ("kW"), 47,000 kW and 135,000 kW for 2018, 2017 and 2016, respectively.

11


Regulation
General
The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. Municipal orders, ordinances and other agreements regarding rates and services adopted by Texas municipalities are subject to review and approval by the PUCT. The FERC has jurisdiction over the Company's wholesale (sales for resale - full requirement customer) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and the FERC are subject to judicial review. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further discussion on Regulatory Matters.
Power Sales Contracts
The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2018.
Franchises and Significant Customers
Franchises
The Company operates under franchise agreements with several cities in its service territory, including one with El Paso, Texas, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its customers within El Paso. Pursuant to the El Paso franchise agreement, the Company pays to the City of El Paso, on a quarterly basis, a fee equal to 5.00% of gross revenues the Company receives for the generation, transmission and distribution of electrical energy and other services within the city. The 2005 El Paso franchise agreement set the franchise fee at 3.25% of gross revenues, but that amount has since been adjusted by two amendments. The 2010 amendment added an incremental fee equal to 0.75% of gross revenues to be placed in a restricted fund to be used by the city solely for economic development and renewable energy purposes. The 2018 amendment, approved on March 20, 2018, and applicable to bills issued on or after October 1, 2018, increased the dedicated incremental fee by 1.00% of gross revenues and extended the term of the franchise agreement by 30 years. Any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso. The El Paso franchise agreement is set to expire on July 31, 2060.
The Company does not have a written franchise agreement with Las Cruces, New Mexico, the second largest city in its service territory. The Company utilizes public rights-of-way necessary to service its customers within Las Cruces under an implied franchise pursuant to state law by satisfying all obligations under the franchise agreement that expired on April 30, 2009. The Company pays the City of Las Cruces a franchise fee of 2.00% of gross revenues the Company receives from services within the City of Las Cruces.
The Company also maintains franchise agreements with other municipalities, and applicable counties, within its service territories.
Military Installations
The Company serves HAFB, White Sands and Fort Bliss. These military installations represent approximately 2.6% of the Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss under which Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company serves White Sands under the applicable New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under which the Company provides retail electric service and limited wheeling services to HAFB under the applicable New Mexico tariffs. As stated in the contract, HAFB will purchase the full output of a Company-owned 5 MW solar facility upon its completed construction, which occurred on October 18, 2018. HAFB's other power requirements are provided under the applicable New Mexico tariffs with limited wheeling services under the contract.
Other Information
Investors should note that we announce material financial information in our filings with the SEC, press releases and public conference calls. Based on guidance from the SEC, we may also use the Investor Relations section of our website (www.epelectric.com) to communicate with investors about the Company. It is possible that the financial information we post there could be deemed to be material information. The information contained on or accessible from our website is not incorporated by reference into and does not constitute a part of this Annual Report on Form 10-K.        

12


Item 1A.
Risk Factors
Like other companies in our industry, our financial results are impacted by weather, the economy of our service territory, market prices for power, fuel prices, and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by local, regional and national macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this Annual Report on Form 10-K and in our other filings with the SEC.
Our Revenues and Profitability Depend Upon Regulated Rates
Our rates are governed by Texas, New Mexico and federal laws and regulations, with our retail rates subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and our wholesale rates subject to regulation by the FERC. There can be no assurance that the laws and regulations or the application thereof in our different jurisdictions will be similar or consistent, which could lead to different treatment of certain matters by our regulators in different jurisdictions. The PUCT Final Order in Docket No. 46831 ("2017 PUCT Final Order") established our current retail base rates in Texas, effective July 18, 2017. In addition, the NMPRC Final Order in Case No. 15-00127-UT ("NMPRC Final Order") established rates in New Mexico that became effective in July 2016.
Our profitability depends on our ability to recover the costs, including a reasonable return on invested capital, of providing electric service to our customers through base rates approved by our regulators. These rates are generally established based on an analysis of the expenses we incur in a historical test year, and as a result, the rates ultimately approved by our regulators may or may not match our expenses at any given time and recovery of expenses may lag behind the occurrence of those expenses. Rates in New Mexico may be established using projected costs and investment for a future test year period in certain instances. While rate regulation is based on the assumption that we will have a reasonable opportunity to recover our costs and earn a reasonable rate of return on our invested capital, there can be no assurance that our future Texas rate cases, New Mexico rate cases, or FERC rate cases will result in rates that will allow us to fully recover our costs including a reasonable return on invested capital, or that our regulators will make similar or consistent determinations with respect to our rates, operations or other matters before our regulators. There can be no assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including costs associated with future plant retirements. It is also likely that third parties will intervene in any cases and challenge whether our costs are reasonable and necessary. If all of our costs are not recovered, or timely recovered, through the retail rates ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely affect our ability to meet our financial obligations.
We May Not Be Able To Recover All Costs of New Generation and Transmission Assets
We received approval, both from the PUCT and the NMPRC, to construct Units 3 and 4, two 89 MW simple-cycle aeroderivative combustion turbines at MPS. In 2016, we completed construction of these units, which began commercial operation in May 2016 and September 2016, respectively. The PUCT approved the inclusion of the Texas jurisdictional portion of MPS Units 3 and 4 in base rates in the 2017 PUCT Final Order. However, the New Mexico jurisdiction portion of MPS Units 3 and 4 have not yet been approved by the NMPRC for inclusion in customer base rates. Accordingly, we are exposed to the risk of failing to recover these costs as well as costs associated with the construction of other new units and transmission and distribution assets.
We announced the results of the 2017 All Source RFP on December 26, 2018, that includes a diverse generation mix. The selected proposals are subject to the execution of contracts following negotiations with the winning bidders, obtaining the applicable environmental and construction related permits and obtaining necessary approvals by the PUCT and the NMPRC.
In addition, for all resource additions, if the contracts, permits, approvals, or the construction of the new unit is not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the PUCT and the NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting from delays in the completion of these new units or other new units.
Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital Programs and Increase Our Funding Obligations for Pensions and Decommissioning

The global credit and equity markets and the overall economy can be extremely volatile which could have a number of adverse effects on our operations, funding obligations and capital programs. For example, tight credit and capital markets could make it difficult and more expensive to raise capital to fund our operations and capital programs. If we are unable to access the

13


credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in stock market performance may reduce the value of our financial assets and decommissioning trust investments and negatively impact our results of operations. Similarly, inflationary increases will increase our future decommission obligations. Such market results may also increase our funding obligations for our pension plans, other post-retirement benefit plans and the NDT. Changes in the corporate interest rates that we use as the discount rate to determine our pension and other post-retirement liabilities may have an impact on our funding obligations for such plans and trusts.

Further, an economic downturn may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. Uncertainty in the credit markets may negatively impact the ability of our customers to finance purchases of our services and could adversely affect the collectability of our receivables. The credit markets and overall economy (including inflationary increases) may also adversely impact our ability to arrange future financings on acceptable terms and therefore our ability to refinance our existing indebtedness could be limited. Furthermore, the credit markets and overall economy may also adversely impact the financial health of our suppliers. If that were to occur, our access to and prices for inventory, supplies and capital equipment could be adversely affected. Our power trading counterparties could also be adversely impacted by the market and economic conditions which could result in reduced wholesale power sales or increased counterparty credit risk.

Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. Partial government shutdowns, such as occurred in 2013 and the end of 2018 and the beginning of 2019, can impact both sales and timely receivables from public authorities, commercial, industrial and residential customers. The occurrence of any of these events could have a material adverse effect on our results of operations, financial condition and cash flows.
There are Inherent Risks in the Ownership of Nuclear Facilities
Our 15.8% ownership interest in Palo Verde, which is the largest nuclear electric generating facility in the U.S., subjects us to a number of risks. A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 30% of our available net generating capacity and provided approximately 44% of our energy requirements for the twelve months ended December 31, 2018. Palo Verde comprises approximately 24% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of O&M expenses. APS is the operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and costs at Palo Verde. Palo Verde operated at a capacity factor of 90.2% and 93.8% in the twelve months ended December 31, 2018 and 2017, respectively.
We participate in Palo Verde with one or more parties who may not have the same goals, strategies, priorities or resources as we do and may compete with us. Furthermore, regulatory compliance issues and financial restraints could cause these parties to make decisions that could potentially be adverse to us. Additionally, if one or more of the participants defaults in performance of its obligations under the ANPP Participation Agreement, the non-defaulting participants must bear all operating, maintenance, and other costs otherwise payable by the defaulting participant (and will receive the generation share of the defaulting participant) in the ratio of their respective share to the total shares of all non-defaulting participants.
As Palo Verde is a nuclear electric generating facility, it is subject to environmental, health and financial risks, such as the ability to obtain adequate supplies of nuclear fuel and water; the ability to dispose of spent nuclear fuel; increases in decommissioning costs due to inflation and regulatory changes, the ability to maintain adequate trust fund reserves for decommissioning; potential liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; cyber attacks, or other causes; and unscheduled outages due to equipment and other problems. If a nuclear incident were to occur at Palo Verde, it could materially and adversely affect our results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause regulatory bodies to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.
We May Not Be Able to Recover All of Our Fuel Expenses from Customers On a Timely Basis Or at All
In general, by law, we are entitled to recover our reasonable and necessary fuel and purchased power expenses from our customers in Texas and New Mexico. NMPRC Case No. 13-00380-UT provides for energy delivered to New Mexico customers from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon a previous purchased power contract. Fuel and purchased power expenses in Texas and New Mexico are subject to reconciliation by the PUCT and NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs such that fuel revenues equal recoverable fuel and purchased power expense including the re-priced energy costs for Palo Verde Unit 3 in New Mexico. In the event that recovery of fuel and purchased power expenses is denied in any reconciliation proceeding, the amounts recorded for

14


fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would incur a loss to the extent of the disallowance.
In New Mexico, the Fuel and Purchased Power Cost Adjustment Clause ("FPPCAC") allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. In Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods of significant increases in natural gas prices, we realize a lag in the ability to reflect increases in fuel costs in our fuel recovery mechanisms in Texas. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely recovery of such costs, we could experience a material negative impact on our cash flow.
Adverse Changes in Our Credit Ratings Could Negatively Affect Our Access to the Capital Markets and our Cost of Borrowed Funds
Access to the capital markets is important to our ability to operate our business and complete our capital projects. Credit rating agencies evaluate our credit ratings on a periodic basis and when certain events occur. These ratings are premised on financial ratios and performance, our regulatory environment and rate mechanisms, resource risks and power supply costs, and other factors. A ratings downgrade could increase fees on the RCF thereby increasing the cost of funding day-to-day working capital requirements, and could also result in higher interest rates on future long-term debt. In addition, any ratings downgrade or placement of our credit ratings on negative watch could have an adverse impact on the price of our common stock. If access to capital were to become significantly constrained or costs of capital increased significantly due to lowered credit ratings, prevailing industry conditions, regulatory constraints, the volatility of the capital markets or other factors, our financial condition and results of operations could be adversely affected.
Weather Conditions Affect the Demand for Electricity or Could Result in Unplanned Outages
Our service territory is in west Texas and southern New Mexico and is particularly susceptible to dry and hot temperatures in the summer months. These seasonal weather patterns result in temperatures that can lead to daytime highs exceeding 100 degrees Fahrenheit for extended periods during the summer when we typically experience peak kWh sales at higher summer rates. Milder temperatures during this period will occur occasionally and result in less kWh sales which will adversely affect our results of operations. From time to time, we experience extreme weather conditions, including high winds (usually in the spring months but can occur during other months), that may result in unplanned outages. Under such conditions, we may incur additional costs to repair and, or, to replace equipment. Depending upon the length and extent of the damage, we may also incur additional purchase power costs. Fallen power lines and poles can cause severe damage to customer property and subject us to claims, all of which could have a material adverse effect on our results of operations and cash flows.
Equipment Failures and Other External Factors Can Adversely Affect Our Results
The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure and severe weather conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these units. In the event of unplanned outages, we must acquire power from other sources at unpredictable costs in order to supply our customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to the extent of the disallowance. Unplanned outages could also prevent us from selling excess power at wholesale. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We may also incur additional capital and operating costs in connection with the physical security and cyber security of transmission lines and generation facilities. Damage to certain transmission and generation facilities due to vandalism or other deliberate acts, or damage due to severe weather could lead to outages or other adverse effects. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. In addition, Palo Verde’s availability is an important factor in realizing off-system sales margins. These factors, as well as interest rates, economic conditions, fuel prices and price volatility could have a material adverse effect on our earnings, cash flow and financial position. While we believe that we maintain adequate insurance coverage for such incidents, there is no assurance that all costs in excess of deductible amounts will be reimbursed or that we can maintain such coverage limits in the

15


future at competitive market rates. In the event future insurance costs and/or deductible amounts increase, our financial condition, operating results and cash flows could be materially adversely affected.
Competition and Deregulation Could Result in a Loss of Customers and Increased Costs
As a result of changes in federal law, our wholesale and large retail customers have access to, in varying degrees, alternative sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. In 2004, the PUCT approved a rule delaying retail competition in our Texas service territory. This rule was codified in the Texas Public Utility Regulatory Act ("PURA") in June 2011. The PURA identifies various milestones that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization in the area that includes our service territory. This and other milestones are not likely to be achieved for a number of years, if at all. There is substantial uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flow and financial condition.
Future Costs of Compliance with Environmental Laws and Regulations Could
Adversely Affect Our Operations and Financial Results
We are subject to extensive federal, state and local environmental laws and regulations relating to discharges into the air, air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources, and health and safety.  Compliance with these legal requirements, which change frequently and often become more restrictive, could require us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchases of air emission allowances and/or offsets. These laws and regulations could also result in limitations in operating hours and/or changes in construction schedules for future generating units. 
Cost of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our rates, could adversely affect our operations and financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of implementation of environmental laws or regulations. For example, the EPA has issued in the recent past various proposed regulations regarding air emissions, such as the revision of the primary and secondary ground-level ozone NAAQS. If these regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our financial results.
Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for
Electricity or Availability of Resources, and Could Result in Increased Compliance Costs
We emit GHG (including carbon dioxide) through the operation of our power plants. Federal legislation has been introduced in both houses of Congress to regulate GHG emissions and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA.
In October 2015, the EPA published a rule establishing guidelines for states to regulate carbon dioxide emissions from existing power plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. On August 31, 2018, the EPA published a proposal to replace the CPP called the Affordable Clean Energy ("ACE") rule. The ACE rule has not yet been finalized. The potential impact of these GHG rules (if and when finalized) on us is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or changes in construction schedules for future generating units.
It is not possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi-state regions or any GHG regulations adopted by the EPA or state environmental agencies will impact our business. However, any legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit GHG, and could have a material adverse effect on our business, financial condition, reputation or results of operations.

16


Adverse Regulatory Decisions or Changes in Applicable Regulations or Laws Could Have a Material Adverse Effect on Our Business or Result in Significant Additional Costs
Our business is subject to extensive federal, state and local laws and regulations regarding safety and performance, siting and construction of facilities, customer service and the rates we can charge our customers, among other things. FERC regulates our wholesale operations, provision of transmission services and compliance with federally mandated reliability standards. FERC has issued a number of rules pertaining to preventing undue discrimination in transmission services and electric reliability standards. Under the Energy Policy Act of 2005, FERC can impose penalties (up to $1,238,271 per violation, per day) for failure to comply with statutes, rules and orders within FERC's jurisdiction, including mandatory electric reliability standards. Additional regulatory authorities have jurisdiction over some of our operations and construction projects, including the EPA, the DOE, the PUCT, the NMPRC and various local municipalities (including the cities of El Paso and Las Cruces).
We must periodically apply for licenses and permits from these various authorities and abide by their respective orders. Should we be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose penalties or disallowances on us, our business could be adversely affected. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to us or our facilities in a manner that may have a detrimental effect on our business or result in significant additional costs because of our obligation to comply with those requirements.
In addition, our service territory borders with Mexico and as such businesses in our service territory rely heavily on commerce with businesses in Mexico. Changes in regulations or enforcement restricting such commerce activities could reduce our customer growth rate and materially adversely affect our results of operations, financial condition and cash flows.
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 ("TCJA") was signed into law, enacting significant changes to the Internal Revenue Code of 1986 (as amended, the "IRC”). Key provisions impacting the Company include a reduction in the federal corporate income tax rate from 35% to 21% effective January 1, 2018, the discontinuation of bonus depreciation for regulated public utilities for assets acquired and placed into service after December 31, 2017, elimination of corporate alternative minimum tax provisions, limitations on the utilization of net operating losses ("NOL") arising after December 31, 2017 to 80% of taxable income with no carryback but with an indefinite carryforward, and additional limitations on the deductibility of executive compensation. We continue to evaluate the impact of the TCJA as regulations related to the TCJA are finalized to determine whether any of these changes could have a material adverse effect on our results of operations, financial condition, and cash flows.
Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our Infrastructure Could Interfere With Our Operations, Could Expose Us or Our Customers or Employees to a Risk of Loss, and Could Expose Us to Liability, Regulatory Penalties, Reputational Damage and Other Harm to Our Business
We rely upon our infrastructure to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology systems for internal accounting purposes and to comply with financial reporting, legal and tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers, breaches due to employee error or malfeasance, system failures, computer viruses, natural disasters, a physical attack on our facilities, or other catastrophic events. The occurrence of any of these events could impact the reliability of our generation, transmission and distribution systems and energy marketing and trading functions; could expose us or our customers or employees to a risk of loss or misuse of confidential information; and could result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business. In addition, we may be required to incur significant costs to prevent or respond to damage caused by these disruptions or security breaches in the future.
Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. The effects of such attacks against us or others in the energy industry could increase the cost of regulatory compliance, increase the cost of insurance coverage or result in a decline in the U.S. economy which could negatively affect our results of operations and financial condition. Ongoing and future governmental efforts to regulate cybersecurity in the energy industry could lead to increased regulatory compliance costs.
As domestic and global cyber threats are on-going and increasing in sophistication, magnitude and frequency, our critical energy infrastructure may be targets of terrorist activities or otherwise could disrupt our business operations. Any such disruptions could result in significant costs to repair damaged facilities and implement increased security measures, which could have a material adverse effect on our results of operations, financial condition and/or cash flows.

17


We May Incur Additional Capital and Operating Costs in Connection with the Physical Security and Cyber Security of New Technologies
We operate in a highly regulated industry that requires the continued operation and development of sophisticated information technology systems and network infrastructure. The introduction of new technology and the emergence of new industry standards and technological hurdles can create unanticipated difficulties, including failures or inadequacy of equipment or software, difficulties in integrating the various components of the equipment, changes in technology, cybersecurity issues and factors outside our control, which could negatively affect our results of operations and financial condition. As we continue to develop new technology to keep up with the demands of the industry and the needs of our customers, we may be required to expend significant capital and other resources to protect against security breaches or to alleviate problems caused by security breaches.
Failure to Maintain the Security of Personally Identifiable Information Could Adversely Affect Us
In connection with our business we and our vendors, suppliers and contractors collect and retain personally identifiable information (e.g., information of our customers, shareholders, suppliers and employees), and there is an expectation that we and such third parties will adequately protect that information. The U.S. regulatory environment surrounding information security and privacy is increasingly demanding. A significant theft, loss or fraudulent use of the personally identifiable information we maintain or failure by our vendors, suppliers and contractors to use or maintain such information in accordance with contractual provisions could adversely impact our reputation and could result in significant costs, fines, litigation and loss of reputation.
The Effects of Technological Advancement, Energy Conservation Measures and Distributed Generation Could Adversely Affect Our Operations and Financial Results
New technologies may emerge that could be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant expenditures to remain competitive. Our future success will depend, in part, on our ability to anticipate and adapt to technological changes in a cost-effective manner and to offer, on a timely basis, services that meet customer demands and evolving industry standards.
Additionally, the electric utility industry is undergoing other technological advances such as the expanded cost effective utilization of energy efficiency measures, energy storage, and distributed generation including solar rooftop projects. Customers’ increased use of energy efficiency measures, energy storage, and distributed generation could result in lower demand. Reduced demand due to energy efficiency measures, energy storage, and the use of distributed generation, to the extent not substantially offset through ratemaking mechanisms, could have a material adverse impact on our financial condition, results of operations and cash flows.
Inflation Could Adversely Affect Our Financial Results
For the past several years, inflation has been relatively low and, therefore has had little impact on our results of operations and financial condition. However, should we experience increases in costs due to inflationary impacts, any delays in requesting and receiving compensatory increases in our base rates could have a material adverse impact on our financial condition, results of operations and cash flows.
Our Line of Business Is Concentrated Solely to the Electric Industry and to One Region
We are a fully vertically integrated electric utility company whose only business is the generation, transmission and distribution of electricity to customers in an area of approximately 10,000 square miles in west Texas and southern New Mexico. Approximately 87% of revenues are directly related to the retail sales of electric power to approximately 425,000 residential, commercial and public authority customers. As such, risks uniquely associated with the utility industry such as changes in utility legislation and regulations, weather patterns in the region and economic conditions will have a greater effect on our overall operating results than otherwise if our operations were more diversified into other lines of business and in a broader geographical area.
The Operation of Transmission Lines on Public and Private Properties, including Indian Lands, Could Result in Uncertainty Related to Continued Easements and Rights-of-way and Significantly Impact Our Business
Portions of our transmission lines are located on public and private properties, including Indian lands, pursuant to easements or other rights-of-way that are effective for specified periods. We are unable to predict the final outcome of pending or future approvals by applicable property owners and governing bodies with respect to renewals of these easements and rights-of-way.

18


Failure to Successfully Operate Our Facilities or Perform Certain Corporate Functions May Adversely Affect Our Operations and Financial Condition
Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks, including:
operator error or failure of equipment or processes, including failure to follow appropriate safety protocols;
the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage;
operating limitations that may be imposed by environmental or other regulatory requirements;
labor disputes;
information technology or financial system failures, including those due to the implementation and integration of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations;
information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims; and
catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, natural disasters, terrorism, pandemic health events or other similar occurrences, which may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts.
Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities or delays in cash collections, any of which could have a material adverse effect on our results of operations, financial condition and/or cash flows.
Our Success Depends on the Availability of the Services of a Qualified Workforce and Our Ability to Attract and Retain Qualified Personnel and Senior Management
Our workforce is aging and many employees have retired in the last few years or are or will become eligible to retire within the next few years.  Although we have undertaken efforts to recruit and train new field service personnel, we may be faced with a shortage of experienced and qualified personnel.  Our costs, including costs to replace employees, benefit (including healthcare) costs, retirement costs, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.
A substantial number of our employees are covered by a collective bargaining agreement that is scheduled to expire in September 2019.  Labor disruptions could occur depending on the outcome of negotiations to renew the terms of this agreement with the union or if a tentative new agreement is not ratified by its members.  In addition, some of our non-represented employees could join this union in the future. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our business, results of operations and/or cash flows.
We depend on our senior management and other key personnel. Our success depends on our ability to attract and retain key personnel. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may adversely affect our operations. In addition, because of the reliance on our management team, our future success depends in part on our ability to identify and develop talent to succeed senior management. Any such occurrences could negatively impact our financial condition and results of operations.
Our Ability to Accurately Report Our Financial Results or Prevent Fraud May Be Adversely Affected if We Fail to Maintain an Effective System of Internal Controls
Effective internal controls are necessary for us to provide reliable financial reports, effectively prevent fraud and operate successfully as a public company. If our efforts to maintain an effective system of internal controls are not successful, we are unable to maintain adequate controls over our financial reporting and processes in the future or we are unable to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed, or we may fail to meet

19


our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock and other securities.
Insufficient Insurance Coverage and Increased Insurance Costs Could Adversely Affect Our Operations and Financial Results
We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.
We Are Subject to Costs and Other Effects of Legal and Regulatory Proceedings, Disputes and Claims
From time to time in the normal course of business, we are subject to various lawsuits, audits, regulatory proceedings, disputes, and claims that could result in adverse judgments or settlements, fines, penalties, injunctions, or other adverse consequences. These matters are subject to a number of uncertainties, and management is often unable to predict the outcome of such matters; resulting liabilities could exceed amounts currently reserved or insured against with respect to such matter. The legal costs and final resolution of matters in which we are involved could have a reputational impact and/or a short- or long-term negative effect on our results of operations, financial condition and/or cash flows. Similarly, the terms of resolution could require us to change our operational practices and procedures, which could also have a material adverse effect on our results of operations, financial condition and/or cash flows.
Provisions in Our Corporate Documents, Franchise Agreements and State Law Could Delay or Prevent a Change in Control of the Company, Even if That Change Would Be Beneficial to Our Shareholders
Our Articles of Incorporation and Bylaws contain provisions that may make acquiring control of the Company difficult and could preclude our shareholders from receiving a change of control premium, including:
provisions relating to the classification, nomination and removal of our directors;
provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;
provisions limiting the ability to call special meetings of the shareholders to the Chairman of the Board, our President and Chief Executive Officer, our Secretary, the majority of the Board of Directors or the holders of at least 25% of the outstanding shares of our capital stock entitled to vote at such meeting;
provisions restricting our ability to engage in a wide range of “Business Combination” transactions with an “Interested Shareholder” (generally, any person who owns 15% or more of our outstanding voting power) or any affiliate or associate of an Interested Shareholder, unless specific conditions are met; and
the authorization given to our Board of Directors or any duly designated committee to issue and set the terms of preferred stock.
Our El Paso franchise agreement states that any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso. In addition, approval of the NMPRC, PUCT and FERC would likely be required in any transaction involving a change of control.
In addition, Texas law prohibits us from engaging in a business combination with any shareholder for three years from the date that person became an affiliated shareholder by beneficially owning 20% or more of our outstanding common stock, in the absence of certain board of director or shareholder approvals.


20


Item 1B.
Unresolved Staff Comments
None.

Item 2.
Properties
The principal properties of the Company are described in Item 1, "Business," and such descriptions are incorporated herein by reference. Transmission and distribution lines are located either on company-owned land, private rights-of-way, easements or on streets or highways by public consent.
The Company owns an executive and administrative office building and various operations centers in El Paso County, Texas, and Doña Ana County, New Mexico. The Company leases land in El Paso, Texas, adjacent to Newman under a lease that expires in June 2033, subject to a renewal option of 25 years. The Company has several other leases for office and parking facilities that expire within the next five years.

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

Item 4.
Mine Safety Disclosures
Not Applicable.

21


PART II
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
The Company’s common stock trades on the New York Stock Exchange ("NYSE") under the symbol "EE."

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

capture.gif

 
As of December 31,
 
2013
 
2014
 
2015
 
2016
 
2017
 
2018
EE
100

 
118

 
117

 
144

 
176

 
164

EEI Index
100

 
129

 
124

 
145

 
163

 
168

NYSE Composite
100

 
104

 
98

 
106

 
123

 
109


22


As of January 31, 2019, there were 2,176 holders of record of the Company’s common stock. The Company has been paying quarterly cash dividends on its common stock since June 30, 2011, and paid a total of $57.5 million in cash dividends during the twelve months ended December 31, 2018. On January 31, 2019, the Board of Directors declared a quarterly cash dividend of $0.36 per share payable on March 29, 2019, to shareholders of record as of the close of business on March 15, 2019. Typically, the Board of Directors reviews the Company’s dividend policy annually in the second quarter of each year. Declaration and payment of dividends is subject to compliance with certain financial tests under Texas law. Since 1999, the Company has also returned cash to shareholders through a stock repurchase program pursuant to which the Company has bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s program, purchases can be made at open market prices or in private transactions. On March 21, 2011, the Board of Directors authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock ("2011 Plan"). No shares of common stock were repurchased during the twelve months ended December 31, 2018, under the 2011 Plan. The table below provides the amount of the fourth quarter issuer purchases of equity securities.

Period
 
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, 2018
 

 
$

 

 
393,816
November 1 to November 30, 2018
 

 

 

 
393,816
December 1 to December 31, 2018
 
12,205

 
50.13

 

 
393,816
_____________________
(a) Represents shares of common stock delivered to us as payment of withholding taxes due upon the vesting of
restricted stock held by our employees, not considered part of the 2011 Plan.
On January 30, 2019, the Company submitted an application with both the NMPRC and the FERC seeking approval to issue shares of common stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more transactions. In order to align the number of shares of common stock held as treasury stock by the Company with various regulatory applications, filings and orders, on January 31, 2019, the Board of Directors of the Company approved the cancellation of 1.4 million shares of Common Stock held as treasury shares by the Company effective upon the later of approval by the FERC of the accounting treatment of the cancellation and March 31, 2019.

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


23


Item 6.
Selected Financial Data
As of and for the following periods (in thousands except for share and per share data):
 
Years Ended December 31,
 
2018 (a)
 
2017
 
2016
 
2015
 
2014
Operating revenue
$
903,603

 
$
916,797

 
$
886,936

 
$
849,869

 
$
917,525

Operating income (b)
$
172,229

 
$
190,059

 
$
187,911

 
$
146,191

 
$
151,163

Net income
$
84,315

 
$
98,261

 
$
96,768

 
$
81,918

 
$
91,428

Basic earnings per share:
 
 
 
 
 
 
 
 
 
Net income
$
2.07

 
$
2.42

 
$
2.39

 
$
2.03

 
$
2.27

Weighted average number of shares outstanding
40,521,364

 
40,414,556

 
40,350,688

 
40,274,986

 
40,190,991

Diluted earnings per share:
 
 
 
 
 
 
 
 
 
Net income
$
2.07

 
$
2.42

 
$
2.39

 
$
2.03

 
$
2.27

Weighted average number of shares and dilutive
 
 
 
 
 
 
 
 
 
 potential shares outstanding
40,642,640

 
40,535,191

 
40,408,033

 
40,308,562

 
40,211,717

Dividends declared per share of common stock
$
1.415

 
$
1.315

 
$
1.225

 
$
1.165

 
$
1.105

Cash additions to utility property, plant and equipment (c)
$
240,021

 
$
199,896

 
$
229,722

 
$
281,458

 
$
277,078

Total assets
$
3,628,502

 
$
3,484,363

 
$
3,376,278

 
$
3,200,607

 
$
3,033,400

Long-term debt, net of current portion
$
1,285,980

 
$
1,195,988

 
$
1,195,513

 
$
1,122,660

 
$
1,122,235

Common stock equity
$
1,164,103

 
$
1,142,165

 
$
1,074,396

 
$
1,016,538

 
$
984,254

________________
(a)
Effective January 1, 2018, the Company implemented Accounting Standards Update ("ASU") 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Liabilities. As required by the new standard, changes in the fair values of the Company's equity investments are recognized in earnings, whereas prior to 2018, such changes were recognized in accumulated other comprehensive income ("AOCI").
(b)
The Company implemented ASU 2017-07, Compensation - Retirement Benefits (Topic 715), in the first quarter of 2018, and as required by the standard, reclassified certain amounts in the financial statements for 2017 and 2016.
(c)
The Company implemented ASU 2016-15, Statement of Cash Flows (Topic 230) in the first quarter of 2018, and as required by the standard, reclassified certain amounts in the financial statements for 2017 and 2016.

24


Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
As you read this Management’s Discussion and Analysis of Financial Condition and Results of Operations, please refer to our Financial Statements and the accompanying notes, which contain our operating results.
Summary of Critical Accounting Policies and Estimates
Our financial statements have been prepared in conformity with U.S. Generally Accepted Accounting Principles ("GAAP"). Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to Financial Statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operation.
Regulatory Accounting
We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of December 31, 2018, we had recorded regulatory assets currently subject to recovery in future rates of approximately $81.8 million and regulatory liabilities of approximately $313.3 million as discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Notes E and K of Notes to Financial Statements. Regulatory tax assets of approximately $20.2 million related to the regulatory treatment of the equity portion of Allowance for Funds Used During Construction ("AFUDC") and approximately $19.3 million related to excess deferred state income taxes are included in regulatory assets. Regulatory tax liabilities of approximately $299.4 million, primarily related to the reduction of the corporate tax rate from 35% to 21%, are included in regulatory liabilities and will be refunded to customers.
In the event we determine that we can no longer apply the Financial Accounting Standards Board's ("FASB") guidance for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, based on regulatory action, we could be required to record a charge against income in the amount of the unamortized balance of the related regulatory assets. Such an action could materially reduce our total assets, specifically our total deferred charges and other assets, and shareholders' equity.
Collection of Fuel Expense
In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT on a periodic basis every one to three years. The NMPRC, in its discretion, may order that a prudence review be conducted to assure that fuel and purchased power costs recovered from customers are prudently incurred. Prior to the completion of a reconciliation proceeding or audit by the PUCT or the NMPRC, we record fuel transactions such that fuel revenues, including fuel costs recovered through the FPPCAC in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation proceeding or an audit, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.
On September 27, 2016, the Company filed an application with the PUCT, designated as PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 31, 2016. On June 29, 2017, the PUCT approved a settlement in this proceeding. The settlement provides for the reconciliation of fuel and purchased power costs incurred from April 1, 2013 through March 31, 2016. As of December 31, 2018, Texas jurisdictional fuel and purchased power costs subject to prudence review are costs from April 1, 2016 through December 31, 2018 that total approximately $353.4 million. The Company's request to reconcile its fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in the NMPRC Final Order. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2018 that total approximately $206.8 million.
The Company recovers fuel and purchased power costs from the Rio Grande Electric Cooperative ("RGEC") pursuant to an ongoing contract with a two-year notice to terminate provision. The contract includes a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC and is updated on an annual basis. This update is reviewed and

25


approved by the RGEC annually in February following the prior calendar year. As of December 31, 2018, the RGEC fuel costs subject to prudence review were approximately $1.1 million.
Decommissioning Costs and Estimated Asset Retirement Obligation
Pursuant to the ANPP Participation Agreement, the rules and regulations of the NRC and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The determination of the estimated liability is based on site-specific estimates, which are updated every three years and involve numerous judgments and assumptions, including estimates of future decommissioning costs at current price levels, escalation rates and discount rates. The Palo Verde ARO is approximately $98.8 million and represents approximately 98% of our total ARO balance of $101.1 million as of December 31, 2018. A 10% increase in the estimates of future Palo Verde decommissioning costs at current price levels would have increased the ARO liability by approximately $10.9 million at December 31, 2018. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements for further discussion.
We are required to fund estimated nuclear decommissioning costs over the life of the generating facilities through the use of external trust funds pursuant to rules of the NRC, PUCT and the ANPP Participation Agreement. Historically, in Texas and New Mexico, we have been permitted to collect the funding requirements for our NDT as part of our rates, except for a portion of Palo Verde Unit 3, which is deregulated in the New Mexico jurisdiction. While we periodically attempt to seek to recover the costs of decommissioning obligations through our rates, we are not able to conclude, given the currently available evidence, that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. We are ultimately responsible for these costs, and our future actions combined with future decisions from regulators will determine how successful we are in this effort.
The funding amounts are based on assumptions about future investment returns and future decommissioning cost escalations. If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the nuclear plant increase beyond our expectations, we would be required to increase our funding to the NDT.
The NDT consists of equity securities and fixed income instruments and are carried at fair value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $134.2 million as of December 31, 2018. A hypothetical 10% increase in interest rates would have reduced the fair values of these funds by $1.7 million at December 31, 2018. The NDT also includes marketable equity securities of approximately $135.9 million at December 31, 2018. A hypothetical 10% decrease in equity prices would have reduced the fair values of these funds by $13.6 million at December 31, 2018. Declines in market prices could require that additional amounts be contributed to our NDT to maintain minimum funding requirements.
We do not anticipate expending monies held in the NDT before 2044 or a later period when decommissioning of Palo Verde begins.
Future Pension and Other Post-retirement Obligations
We maintain a qualified noncontributory defined benefit pension plan, which covers substantially all of our employees, and two non-funded nonqualified supplement plans that provide benefits in excess of amounts permitted under the provisions of the tax law for certain participants in the qualified plan. We also sponsor a plan that provides other post-retirement benefits, such as health and life insurance benefits to retired employees. Our net obligations under these various benefit plans at December 31, 2018 totaled $114.0 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled $2.2 million for the twelve months ended December 31, 2018.
Our pension and other post-retirement benefit liabilities and the related net periodic benefit costs are calculated on the basis of a number of actuarial assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. For 2018, the discount rates used to measure our year end liabilities are based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. As of December 31, 2018, the corresponding weighted-average discount rates range from 4.11% to 4.45% depending upon the benefit plan.
Our overall expected long-term rate of return on assets for the pension trust fund is 7.5% as of January 1, 2019, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. Our overall expected long-term rate of return on assets for the other post-retirement benefits trust, on an after-tax basis, is 6.00% as of January 1, 2019. Both expected long-term rates of return are based on the after-tax weighted average of the expected returns on investments. The expected returns on investments in the pension trust and the other post-retirement benefits trust are based upon the target asset allocations for the two trusts.

26


Our accrued post-retirement benefit liability and the service and interest components of the related net periodic benefit costs are calculated using an actuarial assumption regarding health care cost inflation. For measurement purposes, a 6.0%, 7.0%, 4.5% and 8.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019 for pre-65 medical, pre-65 drug, post-65 medical and post-65 drug, respectively. The health care cost trend rates are assumed to decline steadily to an ultimate rate of 4.5% by 2025 for pre-65 medical and by 2026 for pre-65 and post-65 drug. Post-65 medical trend is assumed to be 4.5% for all years into the future. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan.
The estimated rate of compensation increase used in our retirement plans is 4.5% and is based on recent trends for all non-union employees and the amounts we are contractually obligated for union employees.
The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2018 reported pension liability and our 2018 reported pension expense (in thousands):
 
 
Increase (Decrease)
Actuarial Assumption
 
Impact on Pension Liability
 
Impact on Pension Expense
Discount rate:
 
 
 
 
Increase 1%
 
$
(42,264
)
 
$
(4,024
)
Decrease 1%
 
52,315

 
4,951

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

 
(2,811
)
Decrease 1%
 
N/A

 
2,811

Compensation rate:
 
 
 
 
Increase 1%
 
8,256

 
1,773

Decrease 1%
 
(7,429
)
 
(1,555
)
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2018 other post-retirement benefit obligation and our 2018 reported other post-retirement benefit expense (in thousands):
 
 
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%
 
$
(8,132
)
 
$
(1,171
)
 
$
(384
)
Decrease 1%
 
10,426

 
1,539

 
516

Healthcare cost trend rate:
 
 
 
 
 
 
Increase 1%
 
9,886

 
2,065

 
1,200

Decrease 1%
 
(7,769
)
 
(1,568
)
 
(890
)
Expected long-term rate of return on plan assets:
 
 
 
 
 
 
Increase 1%
 
N/A

 
(398
)
 
N/A

Decrease 1%
 
N/A

 
398

 
N/A


27


Tax Accruals
We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation or audit adjustments can materially affect amounts we recognize in our financial statements. On December 22, 2017, the TCJA was enacted. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the IRC, including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities. See Part II, Item 8, Financial Statements and Supplementary Data, Note K of Notes to Financial Statements for further discussion.
When appropriate, we record a valuation allowance against deferred tax assets to reflect that these tax assets may not be realized. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the results of operations and financial position of the Company. There were no valuation allowances for deferred tax assets as of December 31, 2018.
We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon settlement. The unrecognized tax benefits that do not meet the recognition and measurement standards were $3.2 million as of December 31, 2018.

Overview
The following is an overview of our results of operations for the years ended December 31, 2018, 2017 and 2016. Net income and basic earnings per share for the years ended December 31, 2018, 2017 and 2016 are shown below:
 
 
Years Ended December 31,
 
2018
 
2017
 
2016
Net income (in thousands)
$
84,315

 
$
98,261

 
$
96,768

Basic earnings per share
2.07

 
2.42

 
2.39





28


The following table and accompanying explanations show the primary factors affecting the after-tax change in income between the calendar years ended December 31, 2018 and 2017, 2017 and 2016, and 2016 and 2015 (in thousands):

2018
 
2017
 
2016
 
Prior year December 31 net income
$
98,261

  
$
96,768

  
$
81,918

  
Change in (net of tax):
 
 
 
 
 
 
(Decreased) increased investment and interest income, NDT
(18,419
)
(a)
2,508

(b)
(2,709
)
(b)
(Increased) decreased depreciation and amortization
(4,377
)
(c)
(4,242
)
(d)
3,580

(e)
Palo Verde performance rewards, net
(3,954
)
(f)
3,253

(f)

 
Increased operations and maintenance expenses at fossil-fuel generating plants
(2,518
)
(g)
(482
)
 
(330
)
 
Increased interest on long-term debt (net of capitalized interest) and other
(1,718
)
(h)
(1,632
)
(i)
(3,694
)
(j)
(Decreased) increased retail non-fuel base revenues
(520
)
(k)
8,651

(l)
28,802

(m)
Increased taxes other than income taxes
(108
)
 
(3,465
)
(n)
(1,168
)
(o)
Effective tax rate, other
16,643

(p)
3,379

(q)
(5,343
)
(r)
Decreased (increased) Palo Verde operations and maintenance expenses
2,299

(s)
(1,592
)
(t)
471

 
Increased (decreased) allowance for funds used during construction
931

 
(5,303
)
(u)
(4,887
)
(v)
Other
(2,205
)
 
418

 
128

 
Current year December 31 net income
$
84,315

  
$
98,261

  
$
96,768

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

29


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


30


Impact of New Accounting Standard and Use of Non-GAAP Financial Measures
Upon adoption of ASU 2016-01, Financial Instruments - Recognition and Measurement of Financial Assets and Financial Liabilities, the Company recorded, as of January 1, 2018, a cumulative effect adjustment to retained earnings of $41.0 million, net of tax, for the unrealized gains (losses) related to equity securities held in the NDT. As required by ASU 2016-01, changes in the fair value of equity securities are now recognized in the Company's Statements of Operations. The adoption of the new standard added the potential for significant volatility to the Company's reported results of operations as changes in the fair value of equity securities may occur. Furthermore, the equity investments included in the NDT are significant and are expected to increase significantly during the remaining life (estimated to be 27 to 30 years) of Palo Verde. Accordingly, the Company has provided the following non-GAAP financial measures, which reconcile GAAP net income to non-GAAP adjusted net income and GAAP basic earnings per share to non-GAAP adjusted basic earnings per share, to exclude the impact of changes in fair value of equity securities and realized gains (losses) from the sale of both equity and fixed income securities.
 
Twelve Months Ended
 
December 31,
 
2018
 
2017
 
2016
 
(In thousands except for per share data)
Net income (GAAP)
$
84,315

 
$
98,261

 
$
96,768

Adjusting items before income tax effects
 
 
 
 
 
Unrealized losses, net
18,601

 

 

Realized gains, net
(5,634
)
 
(10,626
)
 
(7,640
)
Total adjustments before income tax effects
12,967

 
(10,626
)
 
(7,640
)
Income taxes on above adjustments
(2,593
)
 
2,125

 
1,528

Adjusting items, net of income taxes
10,374

 
(8,501
)
 
(6,112
)
Adjusted net income (non-GAAP)
$
94,689

 
$
89,760

 
$
90,656

 
 
 
 
 
 
Basic earnings per share (GAAP)
$
2.07

 
$
2.42

 
$
2.39

Adjusted basic earnings per share (non-GAAP)
$
2.33

 
$
2.21

 
$
2.24


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






31


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 to our sole full requirement customer (which are FERC-regulated cost-based wholesale sales within our service territory), accounted for less than 1% of revenues in each of 2018, 2017 and 2016.
Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment mechanisms. Prior to 2017, a significant portion of fuel costs have been recovered through base rates in New Mexico. Effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel costs are no longer recovered through base rates. Beginning July 1, 2016, all fuel costs are recovered through a fuel adjustment mechanism. We record deferred fuel revenues for the difference between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. "Non-fuel base revenues" refers to our revenues from the sale of electricity excluding such fuel costs.
Retail non-fuel base revenue percentages by customer class are presented below:
 
Years Ended December 31,
 
2018
 
2017
 
2016
Residential
48
%
 
46
%
 
46
%
Commercial and industrial, small
31

 
32

 
32

Commercial and industrial, large
6

 
6

 
6

Sales to public authorities
15

 
16

 
16

Total retail non-fuel base revenues
100
%
 
100
%
 
100
%
No retail customer accounted for more than 3% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers represent approximately 79% of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structures in Texas and New Mexico reflect higher base rates during the peak summer season of May through October and lower base rates during November through April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base revenues derived during each quarter for the periods presented:
 
Years Ended December 31,
 
2018
 
2017
 
2016
January 1 to March 31
18
%
 
18
%
 
17
%
April 1 to June 30
28

 
27

 
25

July 1 to September 30
34

 
34

 
38

October 1 to December 31
20

 
21

 
20

Total
100
%
 
100
%
 
100
%
Weather significantly impacts our residential, small commercial and industrial customers, and to a lesser extent, our sales to public authorities. Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree the average outdoor temperature varies from a standard of 65 degrees Fahrenheit, a degree day is recorded. The table below shows heating and cooling degree days compared to a 10-year average for 2018, 2017 and 2016.
 
2018
 
2017
 
2016
 
10-year
Average
Cooling degree days
3,174

 
2,917

 
2,811

 
2,863

Heating degree days
1,937

 
1,522

 
1,851

 
2,056


32


Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew 1.6% and 1.7% in 2018 and 2017, respectively. See the tables presented on pages 35 and 36 which provide detail on the average number of retail customers and the related revenues and kWh sales.
Retail non-fuel base revenues. For the twelve months ended December 31, 2018, retail non-fuel base revenues decreased primarily due to the refunds in 2018 of approximately $28.2 million to customers for the reduction in the federal corporate income tax rate due to the TCJA, partially offset by a $7.7 million base rate increase related to the 2017 PUCT Final Order. Excluding the impact of rate changes related to the 2017 PUCT Final Order, retail non-fuel base revenues increased by $19.8 million, or 3.2%, compared to the twelve months ended December 31, 2017. This increase was primarily due to (i) increased revenues from residential customers of $17.1 million caused by a 5.9% increase in kWh sales that resulted from favorable weather and a 1.7% increase in the average number of residential customers served, and (ii) increased revenues from small commercial and industrial customers of $2.9 million that resulted from favorable weather and a 0.9% increase in the average number of small commercial and industrial customers served. Cooling degree days increased 8.8% in the twelve months ended December 31, 2018, when compared to the twelve months ended December 31, 2017, and were 10.9% above the 10-year average. Heating degree days increased 27.3% in the twelve months ended December 31, 2018, when compared to the twelve months ended December 31, 2017, and were 5.8% below the 10-year average.
For the twelve months ended December 31, 2017, retail non-fuel base revenues increased primarily due to the recognition of $8.8 million approved in the 2017 PUCT Final Order. Excluding the $8.8 million 2017 PUCT Final Order impact, for the twelve months ended December 31, 2017, retail non-fuel base revenues increased $4.5 million, or 0.7%, compared to the twelve months ended December 31, 2016. This increase was primarily due to increased revenues from residential customers of $2.5 million driven by a 1.6% increase in the average number of residential customers served and increased revenues from small commercial and industrial customers of $2.1 million driven by a 2.4% increase in the average number of small commercial and industrial customers served. The Company experienced an overall 1.7% increase in the average number of customers served, partially offset by milder weather when compared to the twelve months ended December 31, 2016. Heating degree days decreased 17.8% in the twelve months ended December 31, 2017, when compared to the twelve months ended December 31, 2016. During our peak summer cooling season, cooling degree days in 2017 were comparable to the same period in 2016.
Fuel revenues. Fuel revenues consist of (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions and the FERC, (ii) deferred fuel revenues which, are comprised of the difference between fuel costs and fuel revenues collected from customers, and (iii) prior to July 1, 2016, fuel costs recovered in base rates in New Mexico. In New Mexico, effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs are no longer recovered through base rates, as they were historically, but are recovered through the FPPCAC. Fuel and purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. Additionally, effective January 1, 2018, pursuant to the final order in NMPRC Case No. 17-00090-UT, the RPS costs for New Mexico are recovered through a separate RPS Cost Rider and not through the FPPCAC. The RPS Cost Rider is updated in an annual NMPRC filing, including a true-up of the prior calendar year’s RPS costs and RPS Cost Rider revenue. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our Texas fixed fuel factor based upon an approved formula at least four months after our last revision, except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over-and under-recoveries are defined as material when they exceed 4% of the previous twelve months' fuel costs.
In March 2018 and March 2017, $1.1 million and $1.4 million, respectively, were credited to customers through the applicable fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage.
We over-recovered fuel costs by $4.8 million in the twelve months ended December 31, 2018. We over-recovered fuel costs by $17.1 million and under-recovered fuel costs by $14.9 million in the twelve months ended December 31, 2017 and 2016, respectively. At December 31, 2018, we had a net fuel over-recovery balance of $11.0 million, including over-recoveries of $8.9 million in Texas, $2.0 million in New Mexico and $0.1 million in FERC jurisdictions. On October 13, 2017, we filed a request to decrease our Texas fixed fuel factor by approximately 19% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. The decrease in our Texas fixed fuel factor became effective beginning with the November 2017 billing month. On April 13, 2018, we filed a request with the PUCT to decrease the Texas fixed fuel factor by approximately 29% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. On April 25, 2018, our proposed fuel factors were approved on an interim basis effective for the first billing cycle of the May 2018 billing month. The revised factor was approved and the docket closed on May 22, 2018. On October 15, 2018, we filed a request with the PUCT to decrease our Texas fixed fuel factor by approximately 6.99% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. On October 25, 2018, our fixed fuel factor was approved on an interim basis effective for the first billing cycle of the November 2018 billing month. The revised factor was approved by the PUCT and the docket closed on November 19, 2018. The Texas fixed fuel factor will continue thereafter until changed by the PUCT.

33


Off-system sales. Off-system sales are sales into wholesale markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. We have shared 100% of margins on non-arbitrage sales (as defined by the settlement in PUCT Docket No. 41852) and 50% of margins on arbitrage sales with our Texas customers since April 1, 2014. We are currently sharing 90% of off-system sales margins with our New Mexico customers (as reaffirmed in NMPRC Case No. 09-00171-UT), and 25% of our off-system sales margins with our sales for resale - full requirement customer under the terms of their contract.
Typically, we realize a significant portion of our off-system sales margins in the first and fourth quarter of each calendar year when our native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. A decrease in natural gas market prices coupled with an increase in wholesale power market prices allowed us to engage in additional off-system sales in the third quarter of 2018 and in the third quarter of 2017. Palo Verde's availability is an important factor in realizing these off-system sales margins.
The table below shows megawatt-hours ("MWhs"), sales revenue, fuel cost, total margins and retained margins made on off-system sales for the twelve months ended December 31, 2018, 2017 and 2016 (in thousands, except for MWhs).
 
Years Ended December 31,
 
2018
 
2017
 
2016
MWh sales
2,687,961

 
2,042,884

 
1,927,508

Sales revenue
$
86,418

 
$
58,986

 
$
45,702

Fuel cost
$
54,299

 
$
46,258

 
$
38,933

Total margins
$
32,119

 
$
12,728

 
$
6,769

Retained margins
$
2,129

 
$
1,673

 
$
1,137

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

34


Comparisons of kWh sales and operating revenues are shown below: 
 
 
 
 
 
Increase (Decrease)
 
 
Years Ended December 31:
2018
 
2017
 
Amount
 
Percent
 
 
kWh sales (in thousands):
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
Residential
2,988,695

 
2,823,260

 
165,435

 
5.9
 %
 
 
Commercial and industrial, small
2,431,920

 
2,410,710

 
21,210

 
0.9

 
 
Commercial and industrial, large
1,050,834

 
1,045,319

 
5,515

 
0.5

 
 
Sales to public authorities
1,563,227

 
1,564,670

 
(1,443
)
 
(0.1
)
 
 
Total retail sales
8,034,676

 
7,843,959

 
190,717

 
2.4

 
 
Wholesale:
 
 
 
 
 
 
 
 
 
Sales for resale - full requirement customer
58,991

 
62,887

 
(3,896
)
 
(6.2
)
 
 
Off-system sales
2,687,961

 
2,042,884

 
645,077

 
31.6

 
 
Total wholesale sales
2,746,952

 
2,105,771

 
641,181

 
30.4

 
 
Total kWh sales
10,781,628

 
9,949,730

 
831,898

 
8.4

 
 
Operating revenues (in thousands):
 
 
 
 
 
 
 
 
 
Non-fuel base revenues:
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
Residential
$
297,597

 
$
287,884

 
$
9,713

 
3.4
 %
 
 
Commercial and industrial, small
194,341

 
198,799

 
(4,458
)
 
(2.2
)
 
 
Commercial and industrial, large
34,920

 
38,403

 
(3,483
)
 
(9.1
)
 
 
Sales to public authorities
95,460

 
97,890

 
(2,430
)
 
(2.5
)
 
 
Total retail non-fuel base revenues (1) (2)
622,318

 
622,976

 
(658
)
 
(0.1
)
 
 
Wholesale:
 
 
 
 
 
 
 
 
 
Sales for resale - full requirement customer
2,780

 
2,730

 
50

 
1.8

 
 
Total non-fuel base revenues
625,098

 
625,706

 
(608
)
 
(0.1
)
 
 
Fuel revenues:
 
 
 
 
 
 
 
 
 
Recovered from customers during the period
156,493

 
218,380

 
(61,887
)
 
(28.3
)
 
 
Over collection of fuel (3)
(4,736
)
 
(17,133
)
 
12,397

 
72.4

 
 
Total fuel revenues (4) (5)
151,757

 
201,247

 
(49,490
)
 
(24.6
)
 
 
Off-system sales (6)
86,418

 
58,986

 
27,432

 
46.5

 
 
Wheeling revenues (7)
19,026

 
18,114

 
912

 
5.0

 
 
Energy efficiency cost recovery (8)
8,888

 

 
8,888

 

 
 
Miscellaneous (7)
8,188

 
8,229

 
(41
)
 
(0.5
)
 
 
Total revenues from customers
899,375

 
912,282

 
(12,907
)
 
(1.4
)
 
 
Other (7) (9)
4,228

 
4,515

 
(287
)
 
(6.4
)
 
 
Total operating revenues
$
903,603

 
$
916,797

 
$
(13,194
)
 
(1.4
)
 
  
Average number of retail customers (10):
 
 
 
 
 
 
 
 
 
Residential
374,138

 
368,044

 
6,094

 
1.7
 %
 
  
Commercial and industrial, small
42,349

 
41,978

 
371

 
0.9

 
  
Commercial and industrial, large
48

 
48

 

 

 
  
Sales to public authorities
5,746

 
5,532

 
214

 
3.9

 
 
Total
422,281

 
415,602

 
6,679

 
1.6

 
  
 ___________________________
(1)
2018 includes $7.7 million of additional revenues compared to 2017 resulting from the 2017 PUCT Final Order, which increased base rates effective July 18, 2017.
(2)
2018 includes a $28.2 million base rate decrease related to the reduction in the federal statutory income tax rate enacted under the TCJA.
(3)
Includes the portion of DOE refunds related to spent fuel storage of $1.1 million and $1.4 million in 2018 and 2017, respectively, that were credited to customers through the applicable fuel adjustment clauses.
(4)
2017 includes $5.0 million related to the Palo Verde performance rewards, net.
(5)
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $8.1 million and $9.8 million in 2018 and 2017, respectively.
(6)
Includes retained margins of $2.1 million and $1.7 million in 2018 and 2017, respectively.
(7)
Represents revenues with no related kWh sales.
(8)
The Company implemented ASU 2014-09, Revenue from Contracts with Customers, in the first quarter of 2018, and following the adoption of the standard, revenues related to reimbursed costs of energy efficiency programs approved by the Company's regulators are reported in operating revenues from customers. Related expenses are reported in O&M expenses.
(9)
Includes energy efficiency bonuses of $1.3 million and $1.5 million in 2018 and 2017, respectively. 
(10)
The number of retail customers presented is based on the number of service locations.

35


 
 
 
 
 
Increase (Decrease)
 
 
Years Ended December 31:
2017
 
2016
 
Amount
 
Percent
 
 
kWh sales (in thousands):
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
Residential
2,823,260

 
2,805,789

 
17,471

 
0.6
 %
 
 
Commercial and industrial, small
2,410,710

 
2,403,447

 
7,263

 
0.3

 
 
Commercial and industrial, large
1,045,319

 
1,030,745

 
14,574

 
1.4

 
 
Sales to public authorities
1,564,670

 
1,572,510

 
(7,840
)
 
(0.5
)
 
 
Total retail sales
7,843,959

 
7,812,491

 
31,468

 
0.4

 
 
Wholesale:
 
 
 
 
 
 
 
 
 
Sales for resale - full requirement customer
62,887

 
62,086

 
801

 
1.3

 
 
Off-system sales
2,042,884

 
1,927,508

 
115,376

 
6.0

 
 
Total wholesale sales
2,105,771