EE 10-K Fiscal year ended Dec. 31, 2019

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•	capital expenditures,

•	earnings,

•	liquidity and capital resources,

•	ratemaking/regulatory matters/compliance matters,

•	litigation,

•	accounting matters, including accounting for taxes and leases,

•	possible corporate restructurings, acquisitions and dispositions, including the merger of Sun Merger Sub Inc. ("Merger Sub"), a Texas corporation and wholly owned subsidiary of Sun Jupiter Holdings LLC, a Delaware limited liability company ("Parent") with and into the Company (the "Merger"),

•	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.

•	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"), and its related transmission facilities, 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 the Company's regulators and other permits related to the Company’s construction programs,

•	the Company's reliance on significant customers,

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•	the credit worthiness of the Company's customers,

•	unscheduled outages of generating units including outages at Palo Verde,

•	changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging competing services and technologies, including distributed generation 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 transmission 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 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,

•	loss of key personnel, the Company's ability to recruit and retain qualified employees and the Company's ability to successfully implement succession planning,

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•	other circumstances affecting anticipated operations, sales and costs, and

•	certain risks and uncertainties associated with the Merger including, without limitation:

◦	the risk that Parent or the Company may be unable to obtain governmental and regulatory approvals required for the Merger, or that required governmental and regulatory approvals or agreements with other parties interested therein may delay the Merger, may subject the Merger to or impose adverse conditions or costs or may cause the parties to abandon the Merger,

◦	the occurrence of any event, change or other circumstances that could give rise to the termination of the Merger or could otherwise cause the failure of the Merger to close,

◦	the risk that a condition to the closing of the Merger may not be satisfied or waived,

◦	the failure of Parent to obtain any financing necessary to complete the Merger,

◦	the outcome of any legal proceedings, regulatory proceedings or enforcement matters that have been or may be instituted relating to the Merger,

◦	the receipt of an unsolicited offer from another party to acquire assets or capital stock of the Company that could interfere with the Merger,

◦	the timing to consummate the Merger,

◦	the costs incurred to consummate the Merger,

◦	the risk that the pendency of the pending Merger disrupts current plans and operations and the potential difficulties in maintaining relationships with customers, employees, regulators or suppliers, and

◦	the diversion of management time and attention from the Company’s ongoing business operations due to the Merger.

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Item 1.	Business

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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.

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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 utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement (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, 2019 , the Company's decommissioning trust fund had a balance of $326.0 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.

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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 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

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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 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. Following the D.C Circuit's August 2013 order, the NRC issued two volumes of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. Publication of these volumes 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.

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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").

•	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

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(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.

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(1)	Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel."

(2)	Estimated production costs consist of:

a.	$279 million for new generating capacity, primarily including:

i.	$136 million of construction costs from 2020 through 2024 for a 228 MW combustion turbine generating unit at Newman with an anticipated operational date in 2023 as a result of the 2017 All Source RFP.

ii.	$134 million of initial construction costs from 2020 through 2024 for a 320 MW combined cycle generating unit to be completed in 2027. The plans for the 320 MW unit are subject to change as the construction program is reviewed and updated in conjunction with recent legislative and regulatory activities pertaining to renewable requirements.

b.	$283 million of other generation costs, including $183 million for Palo Verde.

(3)	Estimated distribution costs include:

a.

$111 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 or Energy Grid Modernization were passed during the Texas and New Mexico legislative sessions that convened in January 2019, and January 2020, respectively. The Texas legislation has been enacted into law, and the New Mexico legislation is awaiting consideration by the state's Governor. With these statutory clarifications, the Company now has the opportunity to request regulatory approval for the deployment of AMI.

(4)	Estimated general plant costs include upgrades of $153 million for information technology projects, including telecommunications network enhancements, $94 million for the Company's facilities, and $31 million for the Company's fleet.

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(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"), 77,000 kW and 47,000 kW for 2019, 2018 and 2017, respectively.

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Item 1A.	Risk Factors

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•	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

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•	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.

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•	negative reactions from the financial markets, including declines in the price of the Company’s common stock due to the fact that the current price may reflect a market assumption that the Merger will be completed;

•	performance shortfalls and missed opportunities as a result of the diversion of the Company’s management’s attention by the Merger; and

•	potential payments by the Company to Parent for damages or, if the Merger Agreement is terminated under certain circumstances, a termination fee of $85 million.

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Item 1B.	Unresolved Staff Comments

Item 2.	Properties

Item 3.	Legal Proceedings

Item 4.	Mine Safety Disclosures

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Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

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Item 6.	Selected Financial Data

(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.

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

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(a)

Investment and interest income, NDT increased in 2019 and decreased in 2018, primarily due to net realized and unrealized gains and losses, respectively, 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 "Use of Non-GAAP Financial Measures" for further details.

(b)	Investment and interest income, NDT increased in 2017, primarily due to changes in realized gains on securities sold from the NDT. Sales of such securities were primarily the result of the Company's efforts to re-balance and further diversify the NDT investments.

(c)

Retail non-fuel base revenues increased primarily due to (i) a $3.8 million increase related to the 1% increase in the City of El Paso franchise fee on gross revenues for services within the City of El Paso applicable to customer billings issued on or after October 1, 2018, (ii) $3.0 million of revenues in Texas for the period of July 30, 2019 through December 31, 2019, related to the Transmission Cost Recovery Factor ("TCRF") settlement agreement approved by the PUCT in Docket No. 49148 on December 16, 2019, and (iii) a $2.0 million increase related to the Distribution Cost Recovery Factor ("DCRF") settlement agreement approved by the PUCT in Docket No. 49395 on September 27, 2019 applicable to customer billings issued on or after October 1, 2019. Excluding the impact of rate changes, retail non-fuel base revenues in 2019 increased $1.0 million primarily due to an increase in the average number of residential customers served.

(d)

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 base rate increase related to the 2017 PUCT Final Order. Excluding the impact of rate changes, retail non-fuel base revenues in 2018 increased $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.

(e)

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.

(f)	O&M expenses at our fossil-fuel generating plants decreased primarily due to decreased outage costs at Newman Units 1 & 2 and Rio Grande Unit 8. These decreases were partially offset by increased outage costs at Newman Unit 4 and increased maintenance costs at MPS and Rio Grande.

(g)	O&M expenses at our fossil-fuel generating plants increased primarily due to outage costs at Rio Grande Unit 8 in 2018.

(h)	Income tax expense-other TCJA impact 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.

(i)	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.

(j)	Strategic transaction costs increased due to costs incurred in connection with the pending Merger.

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(k)	Depreciation and amortization increased primarily due to increases in plant.

(l)	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.

(m)	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.

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(1)	Net income (GAAP) and Adjusted net income (non-GAAP) include a pre-tax charge of $12.1 million, or $0.25 per share, after-tax, of strategic transaction costs.

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(1)	2019 and 2018 include $28.5 million and $28.2 million, respectively, base rate decreases related to the reduction in the federal statutory income tax rate enacted under the TCJA.

(2)	2019 and 2018 include $4.9 million and $1.1 million, respectively, related to the 1% increase in the City of El Paso franchise fee on gross revenues for services within the City of El Paso, applicable to customer billings issued on or after October 1, 2018.

(3)	2019 includes $3.0 million of revenues in Texas for the period of July 30, 2019 through December 31, 2019, related to the TCRF settlement agreement approved in PUCT Docket No. 49148.

(4)	2019 includes a $2.0 million base rate increase related to the DCRF settlement agreement approved in PUCT Docket No. 49395 on September 27, 2019, applicable to customer billings issued on or after October 1, 2019.

(5)	2019 and 2018 include the portion of the DOE refunds related to spent fuel storage of $1.0 million and $1.1 million, respectively, that were credited to customers through the applicable fuel adjustment clauses.

(6)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $5.2 million and $8.1 million in 2019 and 2018, respectively.

(7)	Includes retained margins of $2.5 million and $2.1 million in 2019 and 2018, respectively.

(8)	Represents revenue with no related kWh sales.

(9)	Includes energy efficiency bonuses of $1.6 million and $1.3 million in 2019 and 2018, respectively.

(10)	The number of retail customers presented is based on the number of service locations.

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(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 the 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.

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(1)

We have five outstanding issuances of senior notes. In May 2005, we issued $400.0 million aggregate principal amount of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150.0 million aggregate principal amount of 7.5% Senior Notes due March 15, 2038. In December 2012, we issued $150.0 million aggregate principal amount of 3.3% Senior Notes due December 15, 2022. In December 2014, we issued $150.0 million aggregate principal amount of 5.0% Senior Notes due December 1, 2044. In March 2016, we issued an additional $150.0 million aggregate principal amount of 5.0% Senior Notes due December 1, 2044, for a total principal amount outstanding of 5.0% Senior Notes due December 1, 2044 of $300.0 million. In June 2018, we issued in a private placement offering $125.0 million aggregate principal amount of 4.22% Senior Notes due August 15, 2028.

(2)

We have three series of PCBs outstanding, two of which mature in 2040, and one of which matures in 2042. On February 1, 2019 and April 1, 2019, the Company purchased in lieu of redemption the 2009 Series A 7.25% PCBs with an aggregate principal amount of $63.5 million and the 2009 Series B 7.25% PCBs with an aggregate principal amount of $37.1 million, respectively, utilizing funds borrowed under the RCF. On May 22, 2019, the Company reoffered and sold $63.5 million aggregate principal amount of 2009 Series A 7.25% PCBs and $37.1 million aggregate principal amount of 2009 Series B 7.25% PCBs with a fixed interest rate of 3.60% per annum until the PCBs mature on February 1, 2040 and April 1, 2040, respectively. These two bonds are subject to optional redemption at a redemption price of par on or after June 1, 2029.

(3)

In 2010, we and RGRT entered into a note purchase agreement pursuant to which the RGRT issued and sold $45.0 million aggregate principal amount of 5.04% RGRT Senior Notes, Series C, due August 15, 2020. In June 2018, we and RGRT entered into a note purchase agreement pursuant to which the RGRT issued and sold $65.0 million aggregate principal amount of 4.07% Senior Guaranteed Notes due August 15, 2025.

(4)	This reflects obligations outstanding under the $350.0 million RCF. At December 31, 2019, $84.0 million was borrowed for working capital and general corporate purposes and $29.8 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2019 and assumes this amount will be outstanding for the entire year of 2020.

(5)	Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2019. Gas obligation includes a gas storage contract and a gas transportation contract.

(6)	Some of the nuclear fuel contracts are based on a fixed price, adjusted for a market index. The index used here is the index at the end of 2019.

(7)

At December 31, 2019, the Company met the minimum pension funding levels required under the Employee Retirement Income Security Act of 1974. We also may decide to fund at higher levels and expect to contribute $10.0 million to our retirement plans in 2020. Minimum funding requirements for 2021 and beyond are not included due to the uncertainty of the applicable interest rates and the related return on assets.

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(8)	This obligation is based on the decommissioning funding allowed in PUCT Docket No. 46831, effective July 18, 2017. We have no minimum funding obligation in the New Mexico jurisdiction effective July 1, 2016 pursuant to the NMPRC Final Order. It is possible that our funding requirements could change based on the amounts allowed in future rate filings.

(9)	We lease land in El Paso, Texas, adjacent to Newman under a lease that expires in June 2033, subject to a renewal option of 25 years. We also have several other leases for office, parking facilities and equipment that expire within the next five years.

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Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

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•	pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;

•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and the receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

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•	assessing the actuarial models used by the Company for consistency with generally accepted actuarial standards, and

•	evaluating the Company’s analysis of the 1) discount rate assumptions for the Retirement Income Plan and Other Post-employment Benefit Plan, and 2) healthcare cost trend rate assumptions for the Other Post-employment Benefit Plan. We compared these key assumptions to independently developed expectations using publicly available data.

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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.

Basis of Presentation . The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission ("FERC").

Use of Estimates . The preparation of financial statements in conformity with United States ("U.S.") Generally Accepted Accounting Principles ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). Actual results could differ from those estimates.

Application of the Financial Accounting Standards Board ("FASB" ) Guidance for Regulated Operations. Regulated electric utilities typically prepare their financial statements in accordance with the FASB guidance for regulated operations. The FASB guidance for regulated operations requires the Company to include an allowance for equity and borrowed funds used during construction ("AEFUDC" and "ABFUDC") as a cost of construction of electric plant in service. AEFUDC is recognized as income, and ABFUDC is shown as capitalized interest charges in the Company’s Statements of Operations. The FASB guidance for regulated operations also requires the Company to show certain costs as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already permitted such cost recovery) or will be credited or refunded to the utility’s customers. The resulting regulatory assets or liabilities are amortized in subsequent periods based upon the respective amortization periods reflected in a utility’s regulated rates. See Part II, Item 8, Financial Statements and Supplementary Data, Note E of Notes to Financial Statements for further discussion. The Company applies the FASB guidance for regulated operations for all three of the jurisdictions in which it operates.

Comprehensive Income. Certain gains and losses that are not recognized currently in the Company's Statements of Operations are reported as other comprehensive income in accordance with the FASB guidance for reporting comprehensive income.

Utility Plant. Utility plant is generally reported at cost. The cost of renewals and betterments are capitalized, and the costs of repairs and minor replacements are charged to the appropriate operating expense accounts. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging in average from 5 to 48 years). The average composite depreciation rate utilized in 2019 , 2018 and 2017 was 2.29 % , 2.28 % and 2.27 % , respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost together with the cost of removal, less salvage is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized, if applicable.

The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde Generating Station ("Palo Verde") over the burn period of the fuel that will necessitate the use of the storage casks. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements for further discussion.

Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.

Allowance for Funds Used During Construction ("AFUDC") and Capitalized Interest . The Company capitalizes interest (ABFUDC) and common equity (AEFUDC) costs to construction work in progress and capitalizes interest to nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in the FASB guidance. AFUDC is a non-cash component of income and is calculated monthly and charged to all new eligible construction and capital improvement projects. AFUDC is compounded on a semi-annual basis. The average AFUDC rates used in 2019 , 2018 and 2017 were 5.27 % , 5.95 % and 5.38 % , respectively.

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Asset Retirement Obligations. The FASB guidance sets forth accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. An ARO associated with long-lived assets included within the scope of the FASB guidance is that for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel and legal obligations to perform an asset retirement activity even if the timing and/or settlement are conditioned on a future event that may or may not be within the control of an entity. See Part II, Item 8, Financial Statements and Supplementary Data, Note G of Notes to Financial Statements for further discussion. Under the FASB guidance, these liabilities are recognized as incurred if a reasonable estimate of fair value can be established and are capitalized as part of the cost of the related tangible long-lived assets. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense).

Cash and Cash Equivalents . Temporary cash investments with an original maturity of three months or less are considered cash equivalents. The Company's cash and cash equivalents do not include amounts held in trust by the Company's Palo Verde nuclear decommissioning trust funds ("NDT") or the pension and other post-retirement benefit trust funds.

Investments . The Company’s marketable securities, included in the NDT on the balance sheet, are reported at fair value and consist of cash and equity securities held in the NDT. Investments in equity securities are measured at fair market value. Changes in fair value for equity securities are recognized in the Company's Statements of Operations. Debt securities are classified as "available-for-sale" securities and, as such, unrealized gains and losses are included in accumulated other comprehensive loss as a separate component of common stock equity. However, if declines in the fair value of debt securities below original cost basis are determined to be other than temporary, the declines are reported as losses in the Company's Statements of Operations and a new cost basis is established for the affected securities at fair value. Gains and losses are determined using the cost of the security based on the specific identification basis. See Part II, Item 8, Financial Statements and Supplementary Data, Note Q of Notes to Financial Statements for further discussion.

Derivative Accounting. Accounting for derivative instruments and hedging activities requires the recognition of derivatives as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value of these instruments are recorded in earnings or other comprehensive income. See Part II, Item 8, Financial Statements and Supplementary Data, Note Q of Notes to Financial Statements for further discussion.

Inventories . Inventories, primarily parts, materials, supplies, fuel oil and natural gas are stated at average cost, which is not to exceed recoverable cost.

Operating Revenues . The Company accrues revenues for services rendered, including unbilled electric service revenues. The Company recognizes revenue associated with contracts with customers when performance obligations under the terms of the contract with the customer are satisfied. Revenue is measured as the amount of consideration the Company receives in exchange for transferring goods or providing services to the customer. Taxes collected concurrently with revenue producing activities are excluded from revenue. Unbilled revenues are recorded for estimated amounts of energy delivered in the period following the customer's last billing cycle to the end of the reporting period. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue per kilowatt-hour ("kWh") to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $ 25.6 million and $ 21.6 million as of December 31, 2019 and 2018 , respectively. See Part II, Item 8, Financial Statements and Supplementary Data, Note C of Notes to Financial Statements for further discussion.

The Company’s Texas retail customers are billed under base rates and a fixed fuel factor approved by the Public Utility Commission of Texas ("PUCT"). The Company’s New Mexico retail customers are billed under base rates and a fuel adjustment clause that is adjusted monthly, as approved by the New Mexico Public Regulation Commission ("NMPRC"). The Company's FERC sales for resale customers are billed under formula base rates and fuel factors and a fuel adjustment clause that is adjusted monthly. The Company’s recovery of fuel and purchased power expenses is subject to periodic reconciliations of actual fuel and purchased power expenses incurred to actual fuel revenues collected. The difference between fuel and purchased power expenses incurred and fuel revenues charged to customers is reflected as over/under-collection of fuel revenues, which is included in regulatory liabilities/assets - current in the balance sheets. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further discussion.

Allowance for Doubtful Accounts. The allowance for doubtful accounts represents the Company’s estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections

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environment. Additions, deductions and balances for allowance for doubtful accounts for 2019 , 2018 and 2017 are as follows (in thousands):

	2019				2018				2017
Balance at beginning of year	$	2,070			$	2,300			$	2,156
Additions:
Charged to costs and expense	2,292				2,855				3,141
Recovery of previous write-offs	1,197				1,215				1,122
Uncollectible receivables written off	3,659				4,300				4,119
Balance at end of year	$	1,900			$	2,070			$	2,300

Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting for income taxes. Deferred income taxes are recognized for the estimated future tax consequences of "temporary differences" by applying enacted statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Certain temporary differences are accorded flow-through treatment by the Company's regulators and impact the Company's effective tax rate. The FASB guidance requires that rate-regulated companies record deferred income taxes for temporary differences accorded flow-through treatment at the direction of the regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the Company's regulators have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has recorded regulatory liabilities and assets offsetting such deferred tax assets and liabilities. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date, unless those deferred taxes will be collected from or returned to customers in which case they are recorded as a regulatory asset or liability. See Part II, Item 8, Financial Statements and Supplementary Data, Note L of Notes to Financial Statements for further discussion. The Company recognizes tax assets and liabilities for uncertain tax positions in accordance with the recognition and measurement criteria of the FASB guidance for uncertainty in income taxes. See Part II, Item 8, Financial Statements and Supplementary Data, Note L of Notes to Financial Statements.

On December 22, 2017, the federal legislation commonly referred to as the Tax Cuts and Jobs Act of 2017 ("TCJA") was enacted. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986, as amended, including amendments that significantly changed the taxation of business entities and includes specific provisions related to regulated public utilities. The more significant changes that impact the Company included in the TCJA are a reduction in the federal corporate income tax rate from 35 % to 21 % , elimination of the corporate alternative minimum tax provisions, additional limitations on deductions of executive compensation, and limiting the utilization of net operating losses ("NOL") arising after December 31, 2017 to 80 % of taxable income with no carryback but with an indefinite carryforward. The specific provisions related to regulated public utilities in the TCJA generally provide for the continued deductibility of interest expense, the elimination of bonus depreciation for property acquired and placed into service after December 31, 2017 and the continuance of rate normalization requirements for accelerated depreciation benefits and changes to deferred tax balances as a result of the change in the federal corporate income tax rate.

The tax effects of changes in tax laws must be recognized in the period in which the law is enacted. GAAP also requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, at the date of enactment of the TCJA, the Company’s deferred taxes were re-measured based upon the new federal corporate income tax rate. The decrease in deferred taxes was recorded as a regulatory liability as it will be subject to refund to customers and is recorded at the expected cash flow to be reflected in future rates. See Part II, Item 8, Financial Statements and Supplementary Data, Note L of Notes to Financial Statements for further discussion.

Earnings per Share . The Company’s restricted stock awards are participating securities and earnings per share must be calculated using the two-class method in both the basic and diluted earnings per share calculations. For the basic earnings per share calculation, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares outstanding. The net income allocated to the weighted average number of shares outstanding is then divided by the weighted average number of shares outstanding to derive the basic earnings per share. For the diluted earnings per share, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares and dilutive potential shares outstanding. The Company’s dilutive potential shares outstanding amount is calculated using the treasury stock method for the unvested performance shares. Net income allocated to the weighted average number of shares and dilutive potential shares is then divided by the weighted average number of shares and dilutive potential shares outstanding to derive the

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diluted earnings per share. See Part II, Item 8, Financial Statements and Supplementary Data, Note H of Notes to Financial Statements for further discussion.

Stock-Based Compensation . The Company has a stock-based long-term incentive plan. The Company is required under the FASB guidance to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. Such costs are recognized over the period during which an employee is required to provide service in exchange for the award (requisite service period), which typically is the vesting period. Compensation cost is not recognized for anticipated forfeitures prior to vesting of equity instruments. See Part II, Item 8, Financial Statements and Supplementary Data, Note H of Notes to Financial Statements for further discussion.

Pension and Post-retirement Benefit Accounting . See Part II, Item 8, Financial Statements and Supplementary Data, Note O of Notes to Financial Statements for a discussion of the Company's accounting policies for its employee benefits.

Leases. The Company determines if an arrangement contains a lease and the classification of that lease at inception. Operating lease right-of-use ("ROU") assets represent the Company’s right to use an underlying asset for the lease term and operating lease liabilities represent the obligation to make payments under the lease. ROU assets and lease liabilities are recognized at the lease commencement date based on the estimated present value of the minimum lease payments over the lease term. In determining lease terms, the Company considers any options to extend or terminate the lease that are reasonably certain of being exercised. As the Company’s leases do not include an implicit rate, the Company uses an estimated incremental borrowing rate, at lease commencement, to determine the present value of the future lease payments. In calculating the incremental borrowing rate, the Company takes into consideration recent debt issuances and other data for instruments with similar characteristics. The Company’s lease agreements do not contain residual value guarantees or restrictive covenants. For leases with lease and non-lease components, the Company has elected to account for the consideration as a single lease component. The Company has also elected not to record leases with a term of 12 months or less on the balance sheets. The operating lease ROU assets are included as part of electric plant in service and lease liabilities are included as part of current and non-current liabilities in the Company’s balance sheets. See Part II, Item 8, Financial Statements and Supplementary Data, Note K of Notes to Financial Statements for further discussion.

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New Accounting Standards Adopted in 2019

In February 2016, the FASB issued Accounting Standards Update ("ASU") 2016-02, Leases (Topic 842), to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring qualitative and quantitative disclosures on leasing agreements. ASU 2016-02 maintains a distinction between finance leases and operating leases similar to the distinction under previous lease guidance for capital leases and operating leases. Effective January 1, 2019, the Company adopted ASU 2016-02 using the modified retrospective method, applying the transition provisions to the beginning of the period of adoption rather than to the earliest comparative period presented, which continues to be reported in accordance with previous lease guidance, Accounting Standards Codification Topic 840. The Company adopted the package of practical expedients, which does not require the Company to reassess: (i) whether an arrangement contained a lease, (ii) lease classification for any expired or existing leases, and (iii) initial direct costs for any expired or existing leases. The Company also adopted the practical expedient related to land easements, which allowed carry forward accounting treatment for existing land easements. The most significant impact of adopting ASU 2016-02, as of January 1, 2019, was the recording of approximately $ 6.3 million of operating lease liabilities and related ROU assets with no cumulative effect adjustment to retained earnings. The Company anticipates the ongoing impact of this standard to be immaterial to net income and cash flows. See Part II, Item 8, Financial Statements, Note K of Notes to Financial Statements for further discussion.

In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), as a result of concerns raised due to the enactment of the TCJA. More specifically, because the remeasurement of deferred taxes due to the change in the federal corporate income tax rate is required to be included in income from continuing operations, the tax effects of items within accumulated other comprehensive income ("AOCI") (referred to as stranded tax effects) do not reflect the appropriate tax rate. ASU 2018-02 allows companies an election to reclassify stranded taxes from AOCI to retained earnings. The amount of the reclassification would be the difference between the historical federal corporate income tax rate of 35 % and the newly enacted 21 % federal corporate income tax rate, which approximates $ 7.2 million . The provisions of ASU 2018-02 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2018. The Company adopted ASU 2018-02 on January 1, 2019, and has elected to not reclassify stranded taxes from AOCI to retained earnings.

New Accounting Standards to be Adopted in the Future

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326). ASU 2016-13 changes how companies measure and recognize credit impairment for many financial assets. The new expected credit loss model will require companies to immediately recognize an estimate of credit losses expected to occur over the remaining life of the financial assets that are in the scope of the standard. ASU 2016-13 will be required for reporting periods beginning after December 15, 2019. ASU 2016-13 will be applied in a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is implemented. The Company adopted ASU 2016-13 on January 1, 2020. As part of its implementation process, the Company evaluated the impact of the new standard, which included evaluating the impact of (i) ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments - Credit Losses; Topic 815, Derivatives and Hedging; and Topic 825, Financial Instruments and (ii) ASU 2019-05, Financial Instruments - Credit Losses (Topic 326): Targeted Transition Relief. The adoption of this standard did not have a material impact or require a cumulative effect adjustment to retained earnings. The Company anticipates the ongoing impact of this standard to be immaterial to the Company’s financial position, results of operations, and cash flows.

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The Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), on January 1, 2018, for all of its contracts using the modified retrospective method. There was no cumulative effect adjustment at the initial application of the new standard. In addition, comparative information for periods prior to January 1, 2018, has not been restated and continues to be reported under the accounting standards in effect for those periods.

The following table disaggregates revenue from contracts with customers, for the twelve months ended December 31, 2019 and 2018 (in thousands):

	Years Ended December 31,
	2019				2018
Retail	$	742,510			$	789,676
Wholesale	92,396				90,673
Wheeling (transmission)	22,621				19,026
Total revenues from contracts with customers	857,527				899,375
Other	4,467				4,228
Total operating revenues	$	861,994			$	903,603

The Company recognizes revenue when performance obligations under the terms of the contract with the customer are satisfied. Revenue is measured as the amount of consideration the Company receives in exchange for transferring goods or providing services to the customer. Taxes collected concurrently with revenue producing activities are excluded from revenue.

Retail. Retail contracts represent the Company's primary revenue source. The Company has determined that retail electric service to residential, commercial and industrial, and public authority customers represents an implied daily contract with the customer. The contract is comprised of an obligation to supply and distribute electricity and related capacity. Revenue is recognized, over time, equal to the product of the applicable tariff rates, as approved by the PUCT and the NMPRC, and the volume of the electricity delivered to the customer, or through the passage of time based upon providing the service of standing ready. Unbilled revenues are recognized at month end based on estimated monthly generation volumes and by applying an average revenue per kWh to the number of estimated kWhs delivered but not billed to customers, and recorded as a receivable for the period following the last billing cycle to the end of the reporting period. Retail customers receive a bill monthly, with payment due sixteen days after issuance.

Wholesale. Wholesale contracts primarily include forward power sales into markets outside the Company’s service territory when the Company has competitive generation capacity available, after meeting its regulated service obligations. Pricing is either fixed or based on an index rate with consideration potentially including variable components. Uncertainties regarding the variable consideration will be resolved when the transaction price is known at the point of delivering the energy. The obligation to deliver the electricity is satisfied over time as the customer receives and consumes the electricity. Wholesale customers are invoiced monthly on the 10 ^th day of each month, with payment due by the 20 ^th day of the month. In the case of the sale of renewable energy certificates, the transaction price is allocated to the performance obligation to deliver the confirmed quantity of the certificates based on the stand alone selling price of each certificate. Revenue is recognized as control of the certificates is transferred to the customer. The customer is invoiced upon the completed transfer of the certificates, with payment due within ten business days. Wholesale also includes an annual agreement between the Company and one of its wholesale customers, Rio Grande Electric Cooperative ("RGEC"), which involves the provision of full requirements electric service from the Company to RGEC. The rates for this service are recalculated annually and require FERC approval.

Wheeling (transmission). Wheeling involves the Company providing point-to-point transmission service, which includes the receipt of capacity and energy at designated point(s) and the transfer of such capacity and energy to designated point(s) of delivery on either a firm or non-firm basis for periods of one year or less. The performance obligation to provide capacity and transmit energy is satisfied over time as the Company performs. Transmission customers are invoiced on a monthly basis, with payment due within twenty days of receipt of the invoice.

Other. Other includes alternative revenue program revenue relating to the Company’s potential bonus awards from the PUCT and the NMPRC mandated energy efficiency programs. Both the PUCT and the NMPRC allow for the potential to earn an incentive bonus if the Company achieves its approved energy efficiency goals under the applicable programs. The Company recognizes

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revenue related to the energy efficiency program incentives at the point in time that the amount is objectively determinable generally based upon an approved order from the regulator, is probable of recovery, and if it is expected to be collected within 24 months . Other revenue also includes (i) late payment fees, (ii) leasing income, and (iii) the Company’s allocated share, based on ownership, of sales of surplus effluent water from Palo Verde.

Accounts receivable. Accounts receivable is principally comprised of revenue from contracts with customers. The Company recognizes expense for accounts that are deemed uncollectible in operating expense. The Company recognized $ 2.3 million and $ 2.9 million of uncollectible expense for the twelve months ended December 31, 2019 and 2018 , respectively.

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.

On June 1, 2019, the Company entered into an Agreement and Plan of Merger (the "Merger Agreement"), by and among the Company, Sun Jupiter Holdings LLC, a Delaware limited liability company ("Parent") and Sun Merger Sub Inc., a Texas corporation and wholly owned subsidiary of Parent ("Merger Sub"). Pursuant to the Merger Agreement, on and subject to the terms and conditions set forth therein, Merger Sub will merge with and into the Company (the "Merger"), with the Company continuing as the surviving corporation in the Merger and becoming a wholly owned subsidiary of Parent. Parent and Merger Sub are affiliates of the Infrastructure Investments Fund, an investment vehicle advised by J.P. Morgan Investment Management Inc. ("IIF"). Among other things, the Company, Parent and Merger Sub are required to obtain certain regulatory approvals of the pending Merger as discussed further in Part II, Item 8, Financial Statements and Supplementary Data, Note T of the Notes to the Financial Statements.

On August 13, 2019, the Company, Parent and IIF US Holding 2 LP, an affiliate of IIF, as applicable, filed (i) the joint report and application for regulatory approvals with the PUCT requesting approval of the Merger pursuant to the Texas Public Utility Regulatory Act ("PURA"), which was assigned PUCT Docket No. 49849, (ii) the joint application for regulatory approvals with the NMPRC requesting approval of the Merger pursuant to the New Mexico Public Utility Act ("NMPUA") and NMPRC Rule 450, which was assigned NMPRC Case No. 19-00234-UT, (iii) the joint application requesting approval of the Merger with the FERC under Section 203 of the Federal Power Act, which was assigned FERC Docket No. EC19-120-000, and (iv) the joint application for regulatory approval for the indirect transfer of the Company’s Nuclear Regulatory Commission ("NRC") licenses to Parent from the NRC under the Atomic Energy Act of 1954, which was assigned Docket ID NRC-2019-0214. In addition, on August 13, 2019, the Company and Parent sought the authorization of the Federal Communications Commission ("FCC") to assign or transfer control of the Company’s FCC licenses under FCC File No. 008737430. On December 4, 2019, the Company and Parent received the consent to transfer the FCC licenses.

On August 16, 2019, the Company and Parent filed the notification and report form with the Antitrust Division of the U.S. Department of Justice and the Federal Trade Commission ("FTC") under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the "HSR Act"), as amended, and the rules and regulations promulgated thereunder, which was assigned Transaction Identification No. 2019 1858. On September 3, 2019, the Company and Parent received notice from the FTC granting early termination of the waiting period under the HSR Act.

On November 21, 2019, the Company and IIF reached an agreement in principle with the PUCT staff and most intervenors regarding the Merger. The PUCT issued an order delaying the hearing on the merits in order to assist in reaching a unanimous settlement. The parties continued discussions and provided an update on the status of settlement at the PUCT meeting on December 13, 2019. A non-unanimous settlement was filed with the PUCT on December 18, 2019, resolving substantially all issues in the application. The hearing at the PUCT on the non-unanimous issues was held on January 7, 2020, at the conclusion of which the PUCT requested the Company and IIF attend the PUCT's January 16, 2020 open meeting to answer any follow-up questions. On January 16, 2020, the PUCT approved the Merger and issued its final order on January 28, 2020.

On January 3, 2020, the Company and IIF filed an unopposed stipulation with the NMPRC regarding the Merger. A hearing at the NMPRC for the unopposed stipulation was held on January 16, 2020. On January 16, 2020, the Hearing Examiner agreed

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with the consent of parties to waive briefing. On February 12, 2020, the Hearing Examiner issued an Amended Certification of the Stipulation in which it is recommended that the NMPRC approve the unopposed stipulation subject to the parties agreeing to the Hearing Examiner's modifications. A final order is expected in March 2020.

On December 5, 2019, the FERC requested additional information regarding the parties to the Merger. On January 6, 2020, the Company and IIF filed a joint response to FERC's inquiry. On January 17, 2020, the Company and IIF filed a second supplement to the application. The FERC established a January 27, 2020 deadline date for comments on the filings. Several motions to intervene were filed, along with a protest of the January 6, 2020 response. On February 6, 2020, the Company and IIF filed a reply to the January 27, 2020 protest. The joint applications filed with the FERC and the NRC are pending.

Texas Regulatory Matters

2017 Texas Retail Rate Case Filing. On February 13, 2017, the Company filed with the City of El Paso, other municipalities incorporated in the Company's Texas service territory, and the PUCT in Docket No. 46831, a request for an increase in non-fuel base revenues (the "2017 Texas Retail Rate Case") . On November 2, 2017, the Company filed the Joint Motion to Implement Uncontested Stipulation and Agreement with the Administrative Law Judges ("ALJ") for the 2017 Texas Retail Rate Case.

On December 18, 2017, the PUCT issued a final order in Docket No. 46831 ("2017 PUCT Final Order") , which provides, among other things, for the following: (i) an annual non-fuel base rate increase of $ 14.5 million ; (ii) a return on equity of 9.65 % ; (iii) all new plant in service as filed in the Company's rate filing package was prudent and used and useful and therefore is included in rate base; (iv) recovery of the costs of decommissioning Four Corners Generating Station ("Four Corners") in the amount of $ 5.5 million over a seven year period beginning August 1, 2017; (v) the Company to recover reasonable rate case expenses of approximately $ 3.4 million through a separate surcharge over a three year period; and (vi) a requirement that the Company file a refund tariff if the federal statutory income tax rate, as it relates to the Company, is decreased before the Company files its next rate case. The 2017 PUCT Final Order also established baseline revenue requirements for recovery of future transmission and distribution investment costs (for which the Company could seek recovery after January 1, 2019) and includes a minimum monthly bill of $ 30.00 for new residential customers with distributed generation, such as private rooftop solar. Additionally, the 2017 PUCT Final Order allowed for the annual recovery of $ 2.1 million of nuclear decommissioning funding and establishes annual depreciation expense that is approximately $ 1.9 million lower than the annual amount requested by the Company in its initial filing. Finally, the 2017 PUCT Final Order allowed for the Company to recover revenues associated with the relate back of rates to consumption on and after July 18, 2017, through a separate surcharge.

New base rates, including additional surcharges associated with rate case expenses and the relate back of rates to consumption on and after July 18, 2017, through December 31, 2017 , were implemented in January 2018. The surcharge for the relate back of rates expired on January 9, 2019, with a net over-recovery balance of $ 0.5 million that was addressed in the fuel reconciliation proceeding filed on September 27, 2019, which was assigned PUCT Docket No. 50058.

The 2017 PUCT Final Order required the Company to file a refund tariff if the federal statutory income tax rate, as it relates to the Company, was decreased before the Company files its next general rate case. Following the enactment of the TCJA on December 22, 2017, and in compliance with the 2017 PUCT Final Order, on March 1, 2018, the Company filed with the PUCT and each of its Texas municipalities a proposed refund tariff designed to reduce base charges for Texas customers equivalent to the expected annual decrease of $ 22.7 million in federal income tax expense resulting from the TCJA changes, and an additional refund of $ 4.3 million for the amortization of a regulatory liability related to the reduced tax expense for the months of January through March of 2018 . This filing was assigned PUCT Docket No. 48124. On March 27, 2018, the PUCT approved the Company's proposed refund tariff on an interim basis, subject to refund or surcharge, for customer billing effective April 1, 2018. Each of the Company's municipalities also implemented the Company's proposed tax credits on an interim basis effective April 1, 2018. The refund is reflected in rates over a period of one year beginning April 1, 2018, and will be updated annually until new base rates are implemented pursuant to the Company's next Texas rate case filing. The PUCT issued an order on December 10, 2018, approving the proposed refund tariff. On February 22, 2019, the Company filed with the PUCT and each of its Texas municipalities an application to modify the tax refund tariff to remove the portion of the base rate credit associated with the $ 4.3 million of regulatory liability amortization, which expired March 31, 2019. The filing was assigned PUCT Docket No. 49251 and approved by final order on June 27, 2019. On February 20, 2020, the Company filed its required annual update of the refund factor with the PUCT and each of its Texas municipalities. In its application, the Company proposed that the existing refund factors remain in effect. The filing is currently pending as PUCT Docket No. 50575.

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Texas Energy Efficiency Cost Recovery Factor ("EECRF"). On May 1, 2017, the Company filed its annual application with the PUCT, which was assigned PUCT Docket No. 47125, to establish its EECRF for 2018. In addition to projected energy efficiency costs for 2018 and a reconciliation of collections to prior year actual costs, the Company requested approval of an incentive bonus for the 2016 energy efficiency program results in accordance with PUCT rules. Interim rates were approved effective January 1, 2018. The Company, the PUCT Staff and the City of El Paso reached an agreement that includes an incentive bonus of $ 0.8 million . The agreement was filed on January 25, 2018, and was approved by the PUCT on February 15, 2018.

On May 1, 2018, the Company filed its annual application with the PUCT, which was assigned PUCT Docket No. 48332, to establish its EECRF for 2019. In addition to projected energy efficiency costs for 2019 and a reconciliation of collections to actual costs for the prior year, the Company requested approval of a $ 1.0 million incentive bonus for the 2017 energy efficiency program results in accordance with PUCT rules. Instead of convening a live hearing on the merits of this case, the parties agreed to enter into the record the pre-filed testimony of the parties and certain other exhibits and then file briefs on the contested issues. The ALJ issued a proposal for final decision on November 15, 2018, including the Company's fully requested incentive bonus . On January 17, 2019, the PUCT issued a final order approving a modified bonus amount of $ 0.9 million .

On May 1, 2019, the Company filed its annual application with the PUCT, which was assigned PUCT Docket No. 49496, to establish its EECRF for 2020. In addition to projected energy efficiency costs for 2020 and a reconciliation of collections to actual costs for the prior year, the Company requested approval of a $ 0.8 million incentive bonus for the 2018 energy efficiency program results in accordance with PUCT rules. On July 1, 2019, the Company requested, and received approval for, a suspension of the procedural schedule in order to pursue settlement of the case. On July 12, 2019, the Company informed the ALJ in the case that all parties had agreed in principle on terms for settlement. On August 14, 2019, the Company filed an unopposed settlement agreement and proposed order which resolved all issues in the proceeding, including the requested incentive bonus. The case was remanded on August 16, 2019, to the PUCT for a final order approving the settlement agreement and the Company's EECRF rates. On November 14, 2019, the PUCT issued an order approving the filed settlement.

Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, net of the cost of off-system sales and related shared margins, are recovered from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule ("Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery to continue to be materially under-recovered. Fuel over- and under-recoveries are considered material when they exceed 4 % of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in periodic fuel reconciliation proceedings.

On October 13, 2017, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 47692, to decrease the Texas fixed fuel factor by approximately 19 % to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. The decrease in the Texas fixed fuel factor became effective beginning with the November 2017 billing month.

On April 13, 2018, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 48264, 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, the Company's 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 by the PUCT and the docket closed on May 22, 2018.

On October 15, 2018, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 48781, to decrease the 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, the Company's 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.

On April 29, 2019, the Company filed a petition with the PUCT, which was assigned PUCT Docket No. 49482, requesting authority to implement, beginning on June 1, 2019, a four-month , interim fuel refund of $ 19.4 million in fuel cost over-recoveries, including interest, for the period from April 2016 through March 2019 . On May 30, 2019, the Company's fuel refund credit was approved on an interim basis. The Company implemented the fuel refund in customer bills beginning June 1, 2019. On September

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27, 2019, the PUCT issued a final order approving the fuel refund credits. The fuel refund was completed on September 30, 2019, with a total fuel refund of $ 20.1 million , including interest, returned to Texas customers.

On September 13, 2019, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 49960, to decrease the Texas fixed fuel factor by approximately 12.2 % to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. On September 25, 2019, the Company's fixed fuel factor was approved by the PUCT on an interim basis effective for the first billing cycle of the October 2019 billing month. The Texas fixed fuel factor was determined to be final on October 15, 2019, and will continue until changed by the PUCT.

On November 26, 2019, the Company filed a petition with the PUCT, which was assigned PUCT Docket No. 50292, requesting authority to implement, beginning on January 1, 2020, a three-month , interim fuel refund of $ 15.0 million in fuel cost over-recoveries for the period from April 2019 through October 2019 , including interest for the period from April 2019 through March 2020 . On December 12, 2019, the Company’s fuel refund credit was approved on an interim basis. The Company implemented the fuel refund in customer bills beginning January 1, 2020. As of December 31, 2019, the Company had a net fuel over-recovery balance of approximately $ 16.4 million in Texas.

Fuel Reconciliation Proceeding . On September 27, 2019, the Company filed an application with the PUCT, which was assigned PUCT Docket No. 50058, to reconcile $ 363.0 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2016, through March 31, 2019 . The Company cannot predict the outcome of this filing at this time. The April 1, 2019, through December 31, 2019 , Texas jurisdictional fuel and purchased power costs subject to a future prudence review total approximately $ 51.5 million .

Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program that includes the construction and ownership of a three -megawatt ("MW") solar photovoltaic system located at Montana Power Station. Participation is on a voluntary basis, and customers contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT Docket No. 44800. The Company filed a settlement agreement among all parties on July 1, 2016, approving the program, and the PUCT approved the settlement agreement and program on September 1, 2016. On April 19, 2017, the Company announced that the entire three-MW program was fully subscribed by approximately 1,500 Texas customers. The Community Solar facility began commercial operation on May 31, 2017.

On March 20, 2018, the Company filed a petition with the PUCT and each of its Texas municipalities to expand its community solar program in Texas to include two -MW of solar powered generation from the ten -MW solar photovoltaic facility located at Newman Power Station ("Newman") and to reduce rates under the community solar tariff. The case before the PUCT was assigned PUCT Docket No. 48181 and a hearing was held on December 4, 2018. The ALJ issued a proposal for decision on March 19, 2019, that approved the project as proposed by the Company. On May 9, 2019, the PUCT approved the Company's request to expand the program utilizing the two -MW of solar powered generation available from Newman. New subscriptions for the expanded program were accepted beginning in June 2019, and new rates for all existing and new customers were implemented in customer bills beginning July 1, 2019. As of June 30, 2019, the expanded program was fully subscribed.

Transmission Cost Recovery Factor ("TCRF"). On January 25, 2019, the Company filed an application with the PUCT to establish its TCRF, which was assigned PUCT Docket No. 49148 (the "2019 TCRF rate filing"). The 2019 TCRF rate filing is designed to recover a requested $ 8.2 million of Texas jurisdictional transmission revenue requirement that is not currently being recovered in the Company's Texas base rates for transmission-related investments placed in service from October 1, 2016, through September 30, 2018 , net of retirements. On September 12, 2019, the Company filed an unopposed settlement agreement and proposed order for a TCRF revenue requirement of $ 7.5 million with a provision for recovery of revenue relating to the period from July 30, 2019 to December 31, 2019 . Such revenue through December 31, 2019, approximated $ 3.0 million . On December 16, 2019, the PUCT issued a final order approving the settlement agreement, and the Company's TCRF rates became effective in customer bills beginning January 1, 2020. On January 14, 2020, the Company filed with the PUCT a proposed surcharge in compliance with the final order issued in PUCT Docket No. 49148 for recovery of the $ 3.0 million related to 2019, over a period of 12 months beginning on April 1, 2020. The filing was assigned PUCT Docket No. 50256, and on February 7, 2020, the surcharge was approved through delegated authority by a Commission Administrative Law Judge.

Distribution Cost Recovery Factor ("DCRF"). On March 28, 2019, the Company filed an application with the PUCT and each of its Texas municipalities to establish its DCRF, which was assigned PUCT Docket No. 49395 (the "2019 DCRF rate filing"). The 2019 DCRF rate filing is designed to recover a requested $ 7.9 million of Texas jurisdictional distribution revenue requirement that is not currently being recovered in the Company’s Texas base rates for distribution-related investments placed in service from October 1, 2016, through December 31, 201 8, net of retirements. On August 13, 2019, the Company filed an unopposed settlement

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agreement and proposed order which resolved all issues in the proceeding and approved a DCRF revenue requirement of $ 7.8 million . On September 27, 2019, the PUCT issued a final order approving the settlement agreement, and the Company's DCRF rates became effective in customer bills beginning October 1, 2019.

Newman Unit 6 Certificate of Convenience and Necessity ("CCN"). On November 22, 2019, the Company filed an application with the PUCT for a CCN to own and operate a new, approximately 228 MW, natural gas-fired unit to be constructed at the Company’s existing Newman Power Station. The case was assigned PUCT Docket No. 50277. The proposed unit is called Newman Unit 6. An air permit application for Newman Unit 6 was concurrently submitted to the Texas Commission on Environmental Quality ("TCEQ"). The new unit was selected through a competitive bidding process and is needed to serve growth in customer demand, to replace older and less efficient generators that the Company plans to retire in the next several years, and to help the Company meet its planning reserve margin. The Company cannot predict the outcome of these filings at this time.

Other Required Approvals . The Company has obtained other required approvals for tariffs and other approvals required by the PURA and the PUCT.

New Mexico Regulatory Matters

Future New Mexico Rate Case Filing. The Company was required to file its next New Mexico base rate case no later than July 31, 2019. On July 10, 2019, the NMPRC issued an order approving a joint request by the Company, NMPRC Staff, and the New Mexico Attorney General to delay filing of the Company's next base rate case until after the conclusion of a proceeding addressing the pending Merger. The NMPRC order requires the Company to file its next rate case application within three months of the conclusion of the proceeding addressing the pending Merger in New Mexico. The Company cannot predict the outcome of this filing at this time. See Part II, Item 8, Financial Statements and Supplementary Data, Note T of Notes to Financial Statements for further discussion.

New Mexico Order Commencing Review of the Effects of the TCJA on Regulated New Mexico Utilities. On January 24, 2018, the NMPRC initiated a proceeding in Case No. 18-00016-UT on the impact of the TCJA on New Mexico regulated utilities. On April 4, 2018, the NMPRC issued an order requiring the Company to file a proposed interim rate rider to adjust the Company's New Mexico base revenues in amounts equivalent to the Company's reduced income tax expense for New Mexico customers resulting from the TCJA, to be implemented on or before May 1, 2018. The NMPRC order further requires that the Company record and track a regulatory liability for the excess accumulated deferred income taxes created by the change in the federal corporate income tax rate, consistent with the effective date of the TCJA, and subject to amortization determined by the NMPRC in the Company's next general rate case. The Company recorded such a regulatory liability in 2017. On April 16, 2018, after consultation with the New Mexico Attorney General pursuant to the NMPRC order, the Company filed an interim rate rider with the NMPRC with a proposed effective date of May 1, 2018. The annualized credits expected to be refunded to New Mexico customers approximate $ 4.9 million . The Company implemented the interim rate rider in customer bills beginning May 1, 2018 pursuant to the NMPRC order.

On September 5, 2018, the NMPRC issued an order in Case No. 17-00255-UT involving Southwestern Public Service Company's ("SPS's") request to change rates in which the NMPRC directed SPS to refund the difference in corporate tax rate from January 1, 2018, through the effective date of new rates. SPS appealed the NMPRC order to the New Mexico Supreme Court in Southwestern Public Service Co. v. NMPRC, No. S-1-SC-37248 (" SPS Appeal No. 1 "), challenging the refund as prohibited retroactive ratemaking among other reasons. The New Mexico Supreme Court issued a partial and interim stay of the rates on September 26, 2018. On September 12, 2018, the NMPRC in Case No. 18-00016-UT issued an Order Regarding the Disposition of Tax Savings Under the Federal Tax Cuts and Jobs Act of 2017, which put public utilities on notice that all revenue collected through general rates for the purpose of payment of federal income taxes is and will continue to be subject to possible refund upon a subsequent determination to be made in the appropriate pending or future NMPRC adjudicatory hearing. On October 11, 2018, SPS filed a Notice of Appeal of that NMPRC order to the New Mexico Supreme Court in Southwestern Public Service Co. v. NMPRC, No. S-1-SC-37308 ("SPS Appeal No. 2") . On February 15, 2019, the NMPRC and SPS filed a joint motion for remand and stipulated dismissal of SPS appeals of NMPRC orders with the New Mexico Supreme Court, which among other things, reflected agreements between the NMPRC and SPS, which in part provide that the NMPRC will replace the order in Case No. 17-00255-UT with a new order that eliminates the retroactive TCJA refund and that SPS will request dismissal of SPS Appeals No. 1 and No. 2. On February 28, 2019, the New Mexico Supreme Court remanded SPS Appeal No. 1 back to the NMPRC and dismissed the appeal. On March 6, 2019, the NMPRC issued a revised final order on remand in Case No. 17-00255-UT that, in part, eliminated the retroactive TCJA refund.

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Fuel and Purchased Power Costs. Pursuant to NMPRC Rule 550, fuel and purchased power costs, net of the cost of off-system sales and related shared margins, are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month through the New Mexico Fuel and Purchased Power Cost Adjustment Clause ("FPPCAC"). The Company must file an application for continued use of its FPPCAC no more than four years from the date its last FPPCAC was continued. As required, the Company filed a request to continue use of its FPPCAC with the NMPRC on January 5, 2018, which was assigned Case No. 18-00006-UT. The NMPRC issued a final order in the case on February 13, 2019, which authorized the Company to continue use of its FPPCAC without change and approved the Company's reconciliation of its fuel and purchased power costs for the period January 1, 2015, through December 31, 2016 . New Mexico jurisdictional fuel and purchased power costs subject to a future prudence review are fuel and purchased power costs from January 1, 2017, through December 31, 2019 , that total approximately $ 112.4 million . At December 31, 2019, the Company had a net fuel under-recovery balance of approximately $ 0.3 million related to the FPPCAC in New Mexico.

Amendments to the New Mexico Renewable Energy Act (the "REA"). The REA requires electric utilities to meet a Renewable Portfolio Standard ("RPS") of twenty percent of its total retail sales to New Mexico customers by 2020. Effective June 14, 2019, the New Mexico Energy Transition Act amends the REA (the "Amended REA") to, among other amendments: (i) increase the RPS to forty percent by 2025, fifty percent by 2030, and eighty percent by 2040; (ii) impose a zero-carbon standard by 2045; (iii) eliminate the reduction to the RPS requirement for sales to qualifying large non-governmental customers whose costs are capped under the REA; (iv) set a statutory reasonable cost threshold; and (v) provide cost recovery for certain undepreciated investments and decommissioning costs, such as coal-fired generation, associated with generation required by the NMPRC to be discontinued and replaced with lower or zero-carbon generation. In administering the eighty percent RPS and zero-carbon standards, the Amended REA requires the NMPRC to consider certain factors, including safety, reliability and rate impact to customers. On October 10, 2019, the NMPRC initiated a rulemaking proceeding to implement the Amended REA in Case No. 19-00296-UT. The Company is currently evaluating the impact that the Amended REA may have on its operations. Further, the Company has not determined the costs associated with complying with the Amended REA including potential fines that could be associated with non-compliance.

New Mexico RPS. 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. At December 31, 2019, the Company had a net fuel over-recovery balance related to the RPS Cost Rider of approximately $ 2.2 million . The RPS Cost Rider is updated in an annual NMPRC filing, including a reconciliation of the prior year’s RPS costs and RPS Cost Rider revenue. On October 1, 2019, the Company filed its required application with the NMPRC for its 2019 Annual Renewable Plan in Case No. 19-0099-UT and for adjustment of its RPS Cost Rider for reconciliation of 2018 costs and revenues and to recover RPS costs for 2020. The application requests approvals of the Company's plan to meet requirements of the Amended REA. On November 18, 2019, following a second prehearing conference, the Hearing Examiner issued an order suspending the procedural schedule in order to allow the Company to amend its filed plan after the completion of an ongoing Request for Proposals to solicit possible new resources, by no later than March 31, 2020. The Company cannot predict the outcome of this filing at this time. The order suspending the procedural schedule also required the Company to file a revised RPS Cost Rider to reconcile the net fuel over-recovery balance as of December 31, 2018, which the Company filed on December 2, 2019 and which became effective on January 1, 2020.

5-MW Holloman Air Force Base ("HAFB") Facility CCN. On October 7, 2015, in Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a five -MW solar power generation facility located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a retail contract, which includes a power sales agreement for the facility, to replace the existing load retention agreement that was approved by NMPRC final order issued October 5, 2016, in Case No. 16-00224-UT. The solar generation facility began commercial operation on October 18, 2018.

Expedited Approval for CCN (Solar/Storage Project at New Mexico State University ("NMSU")). On November 20, 2019, the Company filed an application with the NMPRC requesting a certificate of public convenience and necessity to construct, own and operate a three -MW solar powered generation facility coupled with a one -MW battery storage system to be located on NMSU property in Arrowhead Park in the Company's service territory in New Mexico. The Company's application also seeks approval of a special retail rate contract between the Company and NMSU to recover the costs of the new facility and its operations from NMSU. The new facility will be a dedicated Company-owned resource serving NMSU. The Company has requested approval such that the project can begin construction in 2020 to maximize potential tax benefits. This case was assigned NMPRC Case No. 19-00350-UT . Hearings in this case currently are scheduled to begin June 4, 2020. The Company cannot predict the outcome of this filing at this time.

New Mexico Efficient Use of Energy Recovery Factor ("EUERF"). On July 1, 2016, the Company filed its annual application with the NMPRC requesting approval of its 2017 Energy Efficiency and Load Management Plan and to establish the EUERF for

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2017. In addition to projected energy efficiency costs for 2017, the Company requested approval of a $ 0.4 million incentive for 2017 energy efficiency programs in accordance with NMPRC rules. This application was assigned Case No. 16-00185-UT. On February 22, 2017, the NMPRC issued a final order approving the Company’s 2017 Energy Efficiency and Load Management Plan . The Company’s EUERF was approved and effective in customer bills beginning on March 1, 2017. NMPRC rules authorize continuation of the energy efficiency programs and incentive approved in Case No. 16-00185-UT through 2018. The Company recorded approved incentives in operating revenues of $ 0.3 million and $ 0.7 million in 2018 and 2017, respectively, related to its 2015 through 2017 Energy Efficiency and Load Management Plans. During 2019, the Company recorded an incentive in operating revenues of $ 0.4 million related to its 2018 Energy Efficiency Programs.

On July 2, 2018, the Company filed its required application with the NMPRC for approval of its 2019-2021 Energy Efficiency and Load Management Plan and EUERF. The application was assigned Case No. 18-00116-UT. On March 6, 2019, the NMPRC issued a final order approving: (i) the Company's 2019-2021 Energy Efficiency and Load Management Plan, with minor program modifications; (ii) the base incentive of 7.1 % of program expenditures, or approximately $ 0.4 million annually for 2019-2021; and (iii) the continuation of the Company's EUERF. During 2019, the Company recorded incentives in operating revenues of $ 0.4 million related to its 2019 Energy Efficiency and Load Management Plan.

Integrated Resource Plan ("IRP") . On September 17, 2018, the Company filed its IRP with the NMPRC for the period 2018-2037 ("2018 IRP") in Case No. 18-00293-UT as required by regulation and the Joint Stipulation in NMPRC Case No. 15-00241-UT, which was the Company's prior IRP filing. The triennial filing requires a public advisory process as part of the development of the plan to identify a cost-effective portfolio of resources. The filed plan is subject to written public comments filed with the NMPRC to which the Company responded on October 29, 2018. NMPRC Staff filed a written report on November 16, 2018, recommending that the NMPRC return the 2018 IRP to the Company with instructions for re-filing to correct 12 deficiencies identified by the NMPRC Staff report. On December 5, 2018, the NMPRC issued an Order Partially Accepting Integrated Resource Plan; Order Requiring Refiling for Deficiencies. Pursuant to that order, on January 3, 2019, the Company filed an amended 2018 IRP. On January 10, 2019, in light of a pending motion for reconsideration, the NMPRC ordered its Staff to provide additional information and respond to issues raised regarding the filed 2018 IRP. On March 15, 2019, NMPRC Staff filed the additional response and recommended that the Company correct one deficiency that was identified. On September 18, 2019, the NMPRC issued a variance from the IRP rule on commission review, acceptance and action, and closed the docket.

Issuance of Long-Term Debt, Securities Financing, and Guarantee of Debt. On October 7, 2015, the Company received approval in NMPRC Case No. 15-00280-UT to guarantee the issuance of up to $ 65.0 million of long-term debt by the Rio Grande Resources Trust II ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations, which remains effective. Under this authorization, on June 28, 2018 , the RGRT issued $ 65.0 million in aggregate principal amount of 4.07 % Senior Guaranteed Notes due August 15, 2025 . On October 4, 2017, the Company received additional approval in NMPRC Case No. 17-00217-UT to amend and extend the Company's Revolving Credit Facility (" RCF "), increase the commitments under the RCF by up to $ 450.0 million , issue up to $ 350.0 million in long-term debt and to redeem and refinance the $ 63.5 million 2009 Series A 7.25 % Pollution Control Bonds ("PCBs") and the $ 37.1 million 2009 Series B 7.25 % PCBs. The NMPRC approval to issue $ 350.0 million in long-term debt supersedes its prior approval. Under this authorization, on June 28, 2018 , the Company issued $ 125.0 million in aggregate principal amount of the Company's 4.22 % Senior Notes due August 15, 2028 . Additionally, on September 13, 2018, the Company and the Bank of New York Mellon Trust Company, N.A., as trustee of the RGRT, entered into a $ 350.0 million third amended and restated credit agreement. On February 1, 2019 and April 1, 2019 , the Company purchased in lieu of redemption all $ 63.5 million aggregate principal amount of 2009 Series A 7.25 % PCBs and $ 37.1 million aggregate principal amount of 2009 Series B 7.25 % PCBs, respectively. The bonds were purchased utilizing funds borrowed under the RCF. On May 22, 2019, the Company reoffered and sold $ 63.5 million aggregate principal amount of 2009 Series A 7.25 % PCBs and $ 37.1 million aggregate principal amount of 2009 Series B 7.25 % PCBs with a fixed interest rate of 3.60 % per annum until the PCBs mature on February 1, 2040 and April 1, 2040, respectively. The bonds are subject to optional redemption at a redemption price of par on or after June 1, 2029. See Part II, Item 8, Financial Statements and Supplementary Data, Note J of Notes to Financial Statements for further discussion.

On January 30, 2019, the Company submitted an application with the NMPRC 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. The application was assigned Case No. 19-00033-UT, and the NMPRC issued a final order approving the Company's request on March 27, 2019.

Newman Unit 6 CCN. On November 18, 2019, the Company filed an application with the NMPRC for a CCN to own and operate a new, approximately 228 MW, natural gas-fired unit to be constructed at the Company’s existing Newman Power Station. The case was assigned NMPRC Case No. 19-00349-UT. The proposed unit is called Newman Unit 6. The new unit was selected through a competitive bidding process and is needed to serve growth in customer demand, to replace older and less efficient

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generators that the Company plans to retire in the next several years, and to help the Company meet its planning reserve margin. Hearings in the case are currently scheduled to begin on May 11, 2020. The Company cannot predict the outcome of this case at this time.

Long-Term Purchased Power Agreement ("LTPPA") Approval . On November 18, 2019, the Company filed an application with the NMPRC to request prior approval for three LTPPAs pursuant to NMPRC Rule 17.9.551 of the New Mexico Administrative Code ("Rule 551"). The case was assigned NMPRC Case No. 19-00348-UT. The three LTPPAs provide for the purchase of energy and capacity from: (i) a 100 MW solar plant to be constructed in Santa Teresa, New Mexico; (ii) a 100 MW solar plant combined with a 50 MW of battery energy storage to be constructed in Otero County, New Mexico; and (iii) a 50 MW battery energy storage facility to be constructed in Canutillo, Texas. Rule 551 requires that no utility become irrevocably obligated under a LTPPA without first obtaining the NMPRC’s written approval of the agreement. Hearings in the case are currently scheduled to begin on March 3, 2020. The Company cannot predict the outcome of this case at this time.

Other Required Approvals . The Company has obtained other required approvals for tariffs and other approvals as required by the NMPUA and the NMPRC.

Federal Regulatory Matters

Inquiry Regarding the Effect of the TCJA on Commission-Jurisdictional Rates and Order to Show Cause. On March 15, 2018, the FERC issued two show cause orders under Section 206 of the Federal Power Act and Rule 209(a) of the FERC’s Rules of Practice and Procedure, directing 48 individual public utilities with stated transmission rates or transmission formula rates with a fixed line item of 35 % for the federal income tax component to, within 60 days of the date of the orders, either (i) propose revisions to their transmission rates under their open access transmission tariffs or transmission owner tariffs on file with the FERC, or (ii) show cause why they should not be required to do so ("Show Cause Proceeding") . The Company was included in the list of public utilities impacted by the FERC orders. On May 14, 2018, the Company submitted its response, as required by the FERC order, which demonstrated that the reduced annual income tax does not cause the Company's total transmission revenues to become excessive and therefore no rate reduction was justified. Instead, the Company stated in its response that it will prepare for a future filing in which it will seek approval for revised Open Access Transmission Tariff ("OATT") rates that would include the recovery of an increased total transmission revenue requirement from OATT customers based on current circumstances and appropriate forward-looking adjustments. On November 15, 2018, FERC issued an order finding that the Company had demonstrated that no rate reduction was justified and terminating the Show Cause Proceeding. The Company expects to file its request for approval to revise OATT rates in 2020.

Notice of Proposed Rulemaking ("NOPR") on Public Utility Transmission Changes to Address Accumulated Deferred Income Taxes . On November 15, 2018, the FERC issued a NOPR that proposes to direct public utilities with transmission OATT rates, a transmission owner tariff or a rate schedule to determine the amount of excess or deficient accumulated deferred income taxes caused by the TCJA’s reduction to the federal corporate income tax rate and return or recover this amount to or from customers. The NOPR has been assigned FERC Docket No. RM19-5-000. On November 21, 2019, the FERC issued a final rule, Order No. 864, which declined to adopt the proposals to require public utilities such as the Company with transmission stated rates to determine the amount of excess or deficient accumulated deferred income tax caused by the TCJA's reduction to the federal corporate income tax and return or recover this amount to or from customers.

Issuance of Long-Term Debt, Securities Financing, and Guarantee of Debt. On October 31, 2017, the FERC issued an order in Docket No. ES17-54-000 approving the Company’s filing to (i) amend and extend the RCF; (ii) issue up to $ 350.0 million in long-term debt; (iii) guarantee the issuance of up to $ 65.0 million of long-term debt by the RGRT; and (iv) redeem, refinance, and/or replace the $ 63.5 million 2009 Series A 7.25 % PCBs and the $ 37.1 million 2009 Series B 7.25 % PCBs. The order also approved the Company's request to continue to utilize the Company's existing RCF with the ability to amend and extend at a future date. The authorization was effective from November 15, 2017, through November 14, 2019 , and superseded prior FERC approvals. Under this authorization, on June 28, 2018 , the Company issued $ 125.0 million in aggregate principal amount of the Company's 4.22 % Senior Notes due August 15, 2028 , and the RGRT issued $ 65.0 million in aggregate principal amount of its 4.07 % Senior Guaranteed Notes due August 15, 2025 . Also, on September 13, 2018, the Company and the Bank of New York Mellon Trust Company, N.A., as trustee of the RGRT, entered into a $ 350.0 million third amended and restated credit agreement. On February 1, 2019 and April 1, 2019, the Company purchased in lieu of redemption all $ 63.5 million aggregate principal amount of 2009 Series A 7.25 % PCBs and $ 37.1 million aggregate principal amount of 2009 Series B 7.25 % PCBs, respectively . The bonds were purchased utilizing funds borrowed under the RCF.

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On January 30, 2019, the Company submitted an application with 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. Included in the FERC application, which was assigned Docket No. ES19-15-000, the Company also requested various debt-related authorizations: approval to utilize the existing RCF for short-term borrowings not to exceed $ 400.0 million at any one time; to issue up to $ 225.0 million in new long-term debt; and to remarket the $ 63.5 million 2009 Series A 7.25 % PCBs and the $ 37.1 million 2009 Series B 7.25 % PCBs in the form of replacement bonds or senior notes of equivalent value, not to exceed $ 100.6 million . On April 18, 2019, the FERC issued an order authorizing the issuances through April 18, 2021. On May 22, 2019, the Company reoffered and sold $ 63.5 million aggregate principal amount of 2009 Series A 7.25 % PCBs and $ 37.1 million aggregate principal amount of 2009 Series B 7.25 % PCBs with a fixed interest rate of 3.60 % per annum until the PCBs mature on February 1, 2040 and April 1, 2040, respectively. The bonds are subject to optional redemption at a redemption price of par on or after June 1, 2029. See Part II, Item 8, Financial Statements and Supplementary Data, Note J of Notes to Financial Statements for further discussion.

FERC Compliance Audit. On February 6, 2019, the FERC notified the Company that it is commencing an audit that is intended to evaluate the Company’s compliance with: (i) the approved terms, conditions, and rates of its OATT; (ii) the accounting requirements of the Uniform System of Accounts; (iii) the reporting requirements of the FERC Form No. 1 Annual Report and Supplemental Form 3-Q Quarterly Financial Reports; and (iv) the regulations regarding Open Access Same-time Information Systems. The audit covers the period January 1, 2016 to the present and was assigned FERC Docket No. PA19-3-000. The Company cannot predict the outcome or findings, if any, of the FERC audit at this time.

Other Required Approvals. The Company has obtained required approvals for rates, tariffs and other approvals as required by the Federal Power Act and the FERC.

U.S. Department of Energy ("DOE"). The DOE regulates the Company's exports of power to Mexico pursuant to a DOE grant of export authorization. In addition, the Company is the holder of two presidential permits issued by the DOE under which the Company constructed and operates border crossing facilities at the U.S./Mexico border.

Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987, the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements for further discussion of spent fuel storage and disposal costs.

Sales for Resale and Network Transmission Service to RGEC

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The Company's operations are regulated by the PUCT, the NMPRC and the FERC. Regulatory assets represent probable future recovery of previously incurred costs, which will be collected from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Company's balance sheet are presented below (in thousands):

	Amortization Period Ends		December 31, 2019				December 31, 2018
Regulatory assets
Regulatory tax assets	(a)		$	37,771			$	39,519
Loss on reacquired debt (b)	June 2035		13,221				14,074
Final coal reclamation	(c)		3,405				4,065
Four Corners decommissioning	(d)		5,023				5,813
Nuclear fuel postload daily financing charge	(e)		4,197				3,717
Issuance costs related to reissued debt (b)	July 2042		1,991				728
Texas 2015 rate case costs (f)	January 2021		378				747
Texas 2017 rate case costs	January 2021		1,504				2,634
Texas TCRF surcharge (g)	March 2021		2,965				—
New Mexico renewable energy credits and related costs (h)	June 2022		3,588				4,709
New Mexico Palo Verde deferred depreciation	(i)		3,959				4,111
Fuel revenue under-recovery	(j)		327				—
Other regulatory assets	various		2,415				1,703
Total regulatory assets			80,744				81,820
Current portion (amount due within one year)			9,939				6,972
Regulatory assets, non-current			$	70,805			$	74,848
Regulatory liabilities
Regulatory tax liabilities	(k)		$	291,619			$	291,557
Accumulated deferred investment tax credit	(l)		7,122				7,872
New Mexico energy efficiency	(m)		183				1,694
Fuel revenue over-recovery	(j)		18,743				11,047
Other regulatory liabilities	various		760				1,086
Total regulatory liabilities			318,427				313,256
Current portion (amount due within one year)			19,961				14,686
Regulatory liabilities, non-current			$	298,466			$	298,570

______________________________

(a)

This item relates to (i) the regulatory treatment of the equity portion of AFUDC which is recovered in rate base by an offset with the related accumulated deferred income tax liability, and (ii) excess deferred state income taxes which are recovered through amortization to tax expense in cost of service. The amortization period for the excess deferred state income taxes is 15 years as established in the PUCT Final Order in Docket No. 44941 and the NMPRC Final Order in Case No. 15-00127-UT ("NMPRC Final Order ").

(b)	These items are recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance.

(c)	This item relates to coal reclamation costs associated with Four Corners. The Texas portion was approved for recovery in PUCT Docket No. 46308 and is being recovered over seven years through June 2023. The New Mexico portion was approved in NMPRC Case No. 15-00109-UT and the amortization period will be established in the next general rate case.

(d)	This item relates to the decommissioning of Four Corners. The Texas portion was approved for recovery in PUCT Docket No. 46308 and is being recovered over seven years through July 2024. The New Mexico portion was approved in NMPRC Case No. 15-00109-UT and the amortization period will be established in the next general rate case.

(e)	This item is recovered through fuel recovery mechanisms established by tariffs.

(f)	The 2017 PUCT Final Order approved a new recovery period for these costs, beginning January 10, 2018.

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(g)	This item represents revenue associated with the Company's 2019 TCRF rate filing related to the period from July 30, 2019, through December 31, 2019. The recovery period is over a period of 12 months beginning on April 1, 2020. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further discussion.

(h)	This item relates to renewable energy credits and procurement plan costs, of which a component has been approved for recovery in the NMPRC Final Order. The remaining balance will be requested for recovery in the next general rate case.

(i)	The amortization period for this item is based upon the NRC license life for each unit at Palo Verde.

(j)	This item represents the net under or over-recovery of fuel and purchased power expense which is recovered or refunded through fuel rates.

(k)	This item primarily relates to the reduction in the federal corporate income tax rate from 35 % to 21 % as enacted by the TCJA. The amortization period for the recovery on this item will be addressed in the next base rate filings in all jurisdictions. See Part II, Item 8, Financial Statements and Supplementary Data, Note L of Notes to Financial Statements for further discussion.

(l)	The amortization period is based upon the life of the associated assets.

(m)	This item is recovered or credited through the Company's EUERF. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further discussion.

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The table below presents the balance of each major class of depreciable assets at December 31, 2019 (in thousands):

	Gross Plant				Accumulated Depreciation				Net Plant
Nuclear production	$	1,062,849			$	( 380,068	)		$	682,781
Steam and other	1,047,243				( 251,827		)		795,416
Total production	2,110,092				( 631,895		)		1,478,197
Transmission	577,758				( 277,792		)		299,966
Distribution	1,363,300				( 403,410		)		959,890
General	240,455				( 78,932		)		161,523
Intangible	112,545				( 69,356		)		43,189
Total	$	4,404,150			$	( 1,461,385	)		$	2,942,765

The Company owns a 15.8 % interest in each of the three nuclear generating units and common facilities ("Common Facilities") at Palo Verde, in Wintersburg, Arizona. The utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement (the "Palo Verde Participants") include the Company and six other utilities: Arizona Public Service Company ("APS"), Southern California Edison Company, Public Service Company of New Mexico, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District and the Los Angeles Department of Water and Power.

A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2019 and 2018 is as follows (in thousands):

	December 31, 2019								December 31, 2018
	Palo Verde				Other (a)				Palo Verde				Other (a)
Electric plant in service	$	1,062,849			$	98,594			$	1,024,771			$	94,155
Accumulated depreciation	( 380,068		)		( 77,390		)		( 358,606		)		( 75,096		)
Construction work in progress	42,429				532				44,719				1,511
Total	$	725,210			$	21,736			$	710,884			$	20,570

_______________

(a) Includes three jointly-owned transmission lines.

Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 3 to 15 years ). The table below presents the actual and estimated amortization expense for intangible plant for the previous three years and for the next five years (in thousands):

2017	$	6,409
2018	7,297
2019	8,101
2020 (estimated)	8,403
2021 (estimated)	7,667
2022(estimated)	7,063
2023 (estimated)	6,245
2024 (estimated)	4,152

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Palo Verde

The operation of Palo Verde and the relationship among the Palo Verde Participants is governed by the Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended ("ANPP Participation Agreement"). APS serves as operating agent for Palo Verde, and under the ANPP Participation Agreement, the Company has limited ability to influence operations and costs at Palo Verde. Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitlements in the same proportion as their percentage interests in the generating units, and each participant is required to fund its share of fuel, operations and maintenance ("O&M") expense, and capital costs. The Company’s share of direct expenses in Palo Verde and other jointly-owned utility plants is reflected in fuel expense, O&M expense, miscellaneous other deductions, and taxes other than income taxes in the Company’s Statements of Operations. The ANPP Participation Agreement provides that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant. Because it is impracticable to predict defaulting participants, the Company cannot estimate the maximum potential amount of future payment, if any, which could be required under this provision.

Nuclear Regulatory Commission . The 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.

Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 2047, respectively.

Decommissioning . Pursuant to the ANPP Participation Agreement and federal law, the Company funds its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses and is required to maintain a minimum accumulation and funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established the NDT with an independent trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded. At December 31, 2019 , the NDT had a balance of $ 326.0 million , which is above its minimum funding level. The Company monitors the status of the NDT and adjusts contributions accordingly.

Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. In April 2017, the Palo Verde Participants approved the 2016 Palo Verde decommissioning study ("2016 Study"). The 2016 Study estimated that the Company must fund approximately $ 432.8 million (stated in 2016 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $ 52.1 million (stated in 2016 dollars) from the 2013 Palo Verde decommissioning study ("2013 Study"). The effect of this change increased the ARO by $ 3.5 million , which was recorded during the second quarter of 2017, and increased annual expenses starting in April 2017. Although the 2016 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for several years, estimates of the cost to dispose of low-level radioactive waste are subject to uncertainty. As provided in the ANPP Participation Agreement, the participants are required to conduct a new decommissioning study every three years . A 2019 Palo Verde decommissioning study (the "2019 Study") is underway and is expected to be finalized before June 30, 2020, at which time the Company will record the effects of the results of the study. If the expected cash flows as identified in the 2019 Study exceed the expected cash flows identified in the 2016 Study (stated in 2019 dollars), the ARO will increase with a corresponding increase in the ARO asset. Under such circumstances, increases in Palo Verde accretion expense and depreciation expense will occur. While the Company attempts to seek amounts in rates to meet its decommissioning obligations, it is not able to conclude, given the evidence available to it now, that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. The Company is ultimately responsible for these costs and its future actions combined with future decisions from regulators will determine how successful the Company is in this effort.

Spent Fuel and Waste Disposal . Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987, the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste 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

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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 2019, 2018, and 2017, respectively are presented below (in thousands):

Costs Recovery Period		Amount Refunded				Amount Credited to Customers through Fuel Adjustment Clauses				Period Credited to Customers
July 2017 - June 2018		$	1,604			$	1,005			June 2019
July 2016 - June 2017		1,413				1,121				March 2018
July 2015 - June 2016		1,779				1,432				March 2017

On October 31, 2019, APS filed a $ 16.0 million claim for the period July 1, 2018 through June 30, 2019 . The Company's share of this claim is approximately $ 2.5 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. The Company cannot predict when spent fuel shipments to the DOE will commence.

Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation ("ISFSI") to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the 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.

Liability and Insurance Matters . The Palo Verde Participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law, which is currently at $ 13.9 billion . This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $ 450.0 million , and the balance is covered by an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately $ 137.6 million , subject to an annual limit of $ 20.5 million . Based upon the Company's 15.8 % interest in the three Palo Verde units, the Company's maximum potential assessment per incident for all three units is approximately $ 65.2 million , with an annual payment limitation of approximately $ 9.7 million .

The Palo Verde Participants 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 . The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance programs, the Company could be assessed retrospective premium adjustments of up to $ 13.8 million for the current policy period.

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Palo Verde O&M Expense . Included in other O&M expenses are expenses associated with Palo Verde as follows (in thousands):

	Years Ended December 31,
	2019				2018				2017
	$	95,525			$	96,454			$	99,364

The Company records its ARO in accordance with the FASB guidance. This guidance affects the accounting for the decommissioning of Palo Verde and the method used to report the decommissioning obligation. The Company also complies with the FASB guidance for conditional ARO, which primarily affects the accounting for the disposal obligations of the Company’s fuel oil storage tanks, water wells, evaporative ponds and asbestos found at the Company’s gas-fired generating plants. The Company’s ARO are subject to various assumptions and determinations such as: (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for ARO. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.

The ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2016 Study. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements. The ARO liability is calculated by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume responsibility for the permanent disposal of spent fuel, such costs have not been included in the ARO calculation. The Company maintains six external trust funds with an independent trustee that are legally restricted to settling its ARO at Palo Verde. The fair value of the funds at December 31, 2019 is $ 326.0 million .

The FASB guidance requires the Company to revise its previously recorded ARO for any changes in estimated cash flows including changes in estimated probabilities related to timing of settlements. Any changes that result in an upward revision to estimated cash flows shall be treated as a new liability. Any downward revisions to the estimated cash flows result in a reduction to the previously recorded ARO. In the second quarter of 2017, the Company implemented the results of the 2016 Study and revised its ARO related to Palo Verde to increase its estimated cash flows from the 2013 Study to the 2016 Study. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements. The assumptions used to calculate the increases to the Palo Verde ARO liability are as follows:

	Escalation Rate			Credit-Risk Adjusted Discount Rate
Original ARO liability	3.60	%		9.50	%
Incremental ARO liability (2010)	3.60	%		6.20	%
Incremental ARO liability (2016)	3.25	%		4.34	%

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An analysis of the activity of the Company’s total ARO liability from January 1, 2018 through December 31, 2019 , including the effects of each year’s estimate revisions, is presented below (in thousands).

	2019				2018
ARO liability at beginning of year	$	101,108			$	93,029
Liabilities settled	( 118		)		( 272		)
Accretion expense	9,115				8,351
ARO liability at end of year	$	110,105			$	101,108

The Company has transmission and distribution lines which are operated under various land rights agreements. Upon the expiration of any non-perpetual land rights agreement, the Company may have a legal obligation to remove the lines; however, the Company has assessed the likelihood of this occurring as remote. The majority of these agreements are perpetual or include renewal options that the Company routinely exercises. The amount of cost of removal collected in rates for non-legal liabilities has not been material.

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Overview

The Company’s common stock has a stated value of $ 1 per share, with no cumulative voting rights or preemptive rights. Holders of the common stock have the right to elect the Company’s directors and to vote on other matters.

Long-Term Incentive Plan

On May 29, 2014 , the Company’s shareholders approved an amended and restated stock-based long-term incentive plan ("Amended and Restated 2007 LTIP") and authorized the issuance of up to 1.7 million shares of the Company's common stock for the benefit of directors and employees. Under the Amended and Restated 2007 LTIP, shares of the Company's common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may purchase shares on the open market, or issue shares from shares of the Company's common stock the Company has repurchased to meet the share requirements of the Amended and Restated 2007 LTIP. Beginning in 2015, shares of the Company's common stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury stock. However, under the Merger Agreement, the Company is subject to certain limitations in which it may issue common stock pursuant to the Amended and Restated 2007 LTIP. As discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to Financial Statements, the Company accounts for its stock-based long-term incentive plan under the FASB guidance for stock-based compensation.

Restricted Stock with Service Condition and Other Stock-Based Awards . The Company has awarded restricted stock and other stock-based awards under its long-term incentive plan. Restrictions from resale on restricted stock awards generally lapse and awards vest over periods of one to three years , subject to continuous service requirements. The market value of the unvested restricted stock at the date of grant is amortized to expense over the restriction period net of anticipated forfeitures. Other stock-based awards, granted to directors in lieu of cash for retainers and meeting fees, are fully vested and are expensed at fair value on the date of grant and are not included in the tables below. Under the Merger Agreement, stock-based awards that are unvested would be cancelled and converted into a vested right to receive cash upon the closing of the Merger. See Part II, Item 8, Financial Statements and Supplementary Data, Note T of Notes to Financial Statements.

The expense, deferred tax benefit, and current tax benefit recognized related to restricted stock and other stock-based awards in 2019 , 2018 and 2017 is presented below (in thousands):

		2019				2018				2017
Expense (a)		$	2,320			$	3,198			$	2,997
Deferred tax benefit		487				671				1,049
Current tax benefit recognized		112				117				318

_____________________

(a) Any capitalized costs related to these expenses is less than $ 0.3 million for all years.

The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in 2019 , 2018 and 2017 is presented below (in thousands):

		2019				2018				2017
Aggregated intrinsic value		$	3,202			$	3,771			$	3,711
Fair value at grant date		2,667				3,212				2,803

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The unvested restricted stock transactions for 2019 are presented below:

	Total Shares			Weighted Average Grant Date Fair Value				Unrecognized Compensation Expense (b)				Aggregate Intrinsic Value
								(In thousands)				(In thousands)
Restricted shares outstanding at December 31, 2018	93,908			$	51.60
Stock awards (a)	83,585			58.71
Vested	( 50,504	)		52.82
Forfeitures	( 31,185	)		49.38
Restricted shares outstanding at December 31, 2019	95,804			57.89				$	2,853			$	6,504

_______________________

(a) On July 31, 2019, the Company issued a special grant to the Company's former President and Chief Executive Officer ("CEO") of 27,624 shares in accordance with the Amended and Restated 2007 LTIP that is eligible for vesting immediately prior to the closing of the Merger. In the event the Merger Agreement is terminated without the closing of the Merger, these shares will be forfeited.

(b) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the outstanding restricted stock of approximately one year , subject to acceleration under the provisions of the Merger Agreement.

The weighted average fair value per share at grant date for restricted stock and other stock-based awards granted during 2019 , 2018 and 2017 were:

	2019				2018				2017
Weighted average fair value per share	$	58.71			$	54.49			$	49.78

The holder of a restricted stock award has rights as a shareholder of the Company, including the right to vote and receive cash dividends on restricted stock.

Restricted Stock with a Market Condition (Performance Shares) . The Company has granted performance share awards to certain officers under the Company’s Amended and Restated 2007 LTIP, which provides for issuance of Company stock based on the achievement of certain performance criteria over a three -year period. The payout varies between 0 % to 200 % of performance share awards.

Detail of performance shares vested follows:

Date Vested		Payout Ratio			Performance Shares Awarded			Compensation Costs Expensed				Period Compensation Costs Expensed		Aggregated Intrinsic Value
								(In thousands)						(In thousands)
January 29, 2020		150	%		39,027		(a)	$	1,109			2017-2019		$	2,660
January 30, 2019		71	%		39,923			2,143				2016-2018		2,046
January 31, 2018		175	%		68,379			1,499				2015-2017		3,569
January 25, 2017		32	%		11,314			932				2014-2016		512

___________

(a) 6,908 shares vested on December 20, 2019.

In 2020, 2021 and 2022, subject to meeting certain performance criteria and continuous service requirements, additional performance shares could vest. Under the Merger Agreement, shares would vest upon the closing of the Merger. Under the Merger

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Agreement, performance shares that are unvested would be cancelled and converted into a vested right to receive cash upon the closing for the Merger. In accordance with the FASB guidance related to stock-based compensation, the Company recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service period and the compensation expense is only adjusted for forfeitures. As of December 31, 2019, the maximum number of shares that can be issued under the Company's Amended and Restated 2007 LTIP are 145,585 shares.

The fair value at the date of each separate grant of performance shares was based upon a Monte Carlo simulation . The Monte Carlo simulation reflected the structure of the performance plan which calculates the share payout on performance of the Company relative to a defined peer group over a three -year performance period based upon total return to shareholders. The fair value was determined as the average payout of one million simulation paths discounted to the grant date using a risk-free interest rate based upon the constant maturity treasury rate yield curve at the grant date. The expected volatility of total return to shareholders is calculated in accordance with the performance shares' term structure and includes the volatilities of all members of the defined peer group.

The outstanding performance share awards at the 100 % performance level is summarized below:

	Number Outstanding			Weighted Average Grant Date Fair Value				Unrecognized Compensation Expense (b)				Aggregate Intrinsic Value
								(In thousands)				(In thousands)
Performance shares outstanding at December 31, 2018	175,845			$	40.90
Performance share awards	49,826			48.85
Performance shares vested	( 46,831	)		38.78
Performance shares expired	( 16,317	)		38.11
Performance shares forfeited (a)	( 86,677	)		41.52
Performance shares outstanding at December 31, 2019	75,846			47.33				$	302			$	5,149

_______________________

(a) On August 1, 2019, the Company's former President and CEO forfeited the retention grant of 27,624 shares issued on December 15, 2015.

(b) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the awards of approximately one year . Under the Merger Agreement, performance shares that are unvested would be cancelled and converted into a vested right to receive cash upon the closing for the Merger.

A summary of information related to performance shares for 2019 , 2018 and 2017 is presented below:

	2019				2018				2017
Weighted average per share grant date fair value per share of performance shares awarded	$	48.85			$	48.99			$	42.62
Fair value of performance shares vested (in thousands)	1,816				1,499				298
Intrinsic value of performance shares vested (in thousands) (a)	2,514				2,040				512
Compensation expense (in thousands) (b) (c)	153				2,271				2,012
Deferred tax benefit related to compensation expense (in thousands) (b)	32				477				704

_____________________

(a) Based on a 71 % , 100 % and 32 % performance level, respectively.

(b) Includes adjustments for estimated forfeitures.

(c) 2019 includes forfeiture of the Company's former President and CEO's retention grant included in 2018 and 2017.

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Repurchase Program

No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2019 . Detail regarding the Company's stock repurchase program are presented below:

	Since 1999 (a)				Authorized Shares
Shares repurchased (b) (c)	25,406,184
Cost, including commission (in thousands)	$	423,647
Total remaining shares available for repurchase at December 31, 2019 (d)					393,816

______________________

(a)	Represents repurchased shares and cost since inception of the stock repurchase program in 1999.

(b)	Shares repurchased does not include 86,735 treasury shares related to employee compensation arrangements that were not part of the Company's repurchase program.

(c)	Beginning in 2015, shares of the Company's common stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury stock. The Company has issued 396,657 treasury shares since 2015 including 51,305 shares during 2019.

(d)	The Company may make purchases of shares of its common stock pursuant to its authorized program in open market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans or the repurchased shares may be retired.

Authorization to Issue and Retire Shares

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. The Company received final approvals for such issuances from the NMPRC and the FERC on March 27, 2019 and April 18, 2019 respectively. Under the Merger Agreement, the Company cannot issue shares of common stock, subject to limited exceptions, without the prior written consent of Parent. 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 May 23, 2019, the Board of Directors of the Company (the "Board of Directors") approved the cancellation of 1.4 million shares of common stock held as treasury shares by the Company effective May 31, 2019.

Dividend Policy

On December 27, 2019, the Company paid $ 15.7 million in quarterly cash dividends to shareholders. The Company paid a total of $ 61.7 million , $ 57.5 million and $ 53.3 million in cash dividends during the twelve months ended December 31, 2019 , 2018 and 2017 , respectively.

Under the Merger Agreement, the Company is not allowed to declare or pay dividends or distributions on shares of common stock in an amount in excess of $ 0.385 per share for quarterly dividends declared before June 1, 2020 and $ 0.41 per share for quarterly dividends declared on or after June 1, 2020. See Part II, Item 8, Financial Statements, Note T of Notes to Financial Statements for further discussion.

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Basic and Diluted Earnings Per Share

The FASB guidance requires the Company to include share-based compensation awards that qualify as participating securities in both basic and diluted earnings per share to the extent they are dilutive. A share-based compensation award is considered a participating security if it receives non-forfeitable dividends or may participate in undistributed earnings with common stock. The Company awards unvested restricted stock, which qualifies as a participating security. The basic and diluted earnings per share are presented below:

	Years Ended December 31,
	2019				2018				2017
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,605,597				40,521,364				40,414,556
Dilutive effect of unvested performance awards	75,624				121,276				120,635
Diluted number of common shares outstanding	40,681,221				40,642,640				40,535,191
Basic net income per common share:
Net income	$	123,037			$	84,315			$	98,261
Income allocated to participating restricted stock	( 402		)		( 297		)		( 368		)
Net income available to common shareholders	$	122,635			$	84,018			$	97,893
Diluted net income per common share:
Net income	$	123,037			$	84,315			$	98,261
Income reallocated to participating restricted stock	( 402		)		( 296		)		( 368		)
Net income available to common shareholders	$	122,635			$	84,019			$	97,893
Basic net income per common share:
Distributed earnings	$	1.515			$	1.415			$	1.315
Undistributed earnings	1.505				0.655				1.105
Basic net income per common share	$	3.020			$	2.070			$	2.420
Diluted net income per common share:
Distributed earnings	$	1.515			$	1.415			$	1.315
Undistributed earnings	1.495				0.655				1.105
Diluted net income per common share	$	3.010			$	2.070			$	2.420

The amount of restricted stock awards and performance shares at 100 % performance level excluded from the calculation of the diluted number of common shares outstanding because their effect was antidilutive is presented below:

		Year Ended December 31,
		2019			2018			2017
Restricted stock awards		51,647			62,836			67,739
Performance shares (a)		10,913			22,815			—

_____________________

(a)	Certain performance shares were excluded from the computation of diluted earnings per share as no payouts would have been required based upon performance at the end of each corresponding period.

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Upon adoption of ASU 2016-01, Financial Instruments-Overall, the Company recorded, on January 1, 2018, a cumulative effect adjustment, net of income taxes, to increase retained earnings by $41.0 million with an offset to AOCI. Changes in Accumulated Other Comprehensive Income (Loss) (net of tax) by component are presented below (in thousands):
			Unrecognized Pension and Post-retirement Benefit Costs				Net Unrealized Gains (Losses) on Marketable Securities				Net Losses on Cash Flow Hedges				Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2016			$	( 23,928	)		$	28,463			$	( 11,651	)		$	( 7,116	)
	Other comprehensive income before reclassifications		7,951				20,251				—				28,202
	Amounts reclassified from accumulated other comprehensive income (loss)		( 1,813		)		( 8,524		)		309				( 10,028		)
Balance at December 31, 2017			( 17,790		)		40,190				( 11,342		)		11,058
	Cumulative effect adjustment		—				( 41,028		)		—				( 41,028		)
	Other comprehensive loss before reclassifications		( 4,589		)		( 3,240		)		—				( 7,829		)
	Amounts reclassified from accumulated other comprehensive income (loss)		( 2,544		)		1,136				423				( 985		)
Balance at December 31, 2018			( 24,923		)		( 2,942		)		( 10,919		)		( 38,784		)
	Other comprehensive income (loss) before reclassifications		( 9,424		)		4,655				—				( 4,769		)
	Amounts reclassified from accumulated other comprehensive income (loss)		( 4,144		)		( 1,713		)		458				( 5,399		)
Balance at December 31, 2019			$	( 38,491	)		$	—			$	( 10,461	)		$	( 48,952	)

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Amounts reclassified from Accumulated Other Comprehensive Income (Loss) for the twelve months ended December 31, 2019 , 2018 and 2017 are as follows (in thousands):

Details about Accumulated Other Comprehensive Income (Loss) Components				2019				2018				2017				Affected Line Item in the Statements of Operations
Amortization of pension and post-retirement benefit costs:
	Prior service benefit			$	8,740			$	9,657			$	9,657			Miscellaneous non-operating income
	Net loss			( 3,415		)		( 6,387		)		( 6,776		)		Miscellaneous non-operating deductions
				5,325				3,270				2,881				Income before income taxes
	Income tax effect			( 1,181		)		( 726		)		( 1,068		)		Income tax expense
				4,144				2,544				1,813				Net income
Marketable securities:
	Net realized gain (loss) on sale of securities			2,232				( 1,445		)		10,626				Investment and interest income, net
				2,232				( 1,445		)		10,626				Income before income taxes
	Income tax effect			( 519		)		309				( 2,102		)		Income tax expense
				1,713				( 1,136		)		8,524				Net income
Loss on cash flow hedge:
	Amortization of loss			( 605		)		( 568		)		( 532		)		Interest on long-term debt and revolving credit facility
				( 605		)		( 568		)		( 532		)		Income before income taxes
	Income tax effect			147				145				223				Income tax expense
				( 458		)		( 423		)		( 309		)		Net income
	Total reclassifications			$	5,399			$	985			$	10,028

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Outstanding long-term debt and financing obligations, net of issuance costs, are as follows:

	December 31,
	2019				2018
	(In thousands)
Long-Term Debt:
Pollution Control Bonds (1):
3.60% 2009 Series A refunding bonds, due 2040 (3.82% effective interest rate)	$	62,765			$	—
3.60% 2009 Series B refunding bonds, due 2040 (3.84% effective interest rate)	36,640				—
7.25% 2009 Series A refunding bonds, (7.46% effective interest rate)	—				62,695
7.25% 2009 Series B refunding bonds, (7.49% effective interest rate)	—				36,544
4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate)	58,560				58,530
Total Pollution Control Bonds	157,965				157,769
Senior Notes (2):
Senior Notes-Public:
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)	149,443				149,269
6.00% Senior Notes, net of discount, due 2035 (6.58% effective interest rate)	394,435				394,231
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	147,502				147,441
5.00% Senior Notes, net of premium, due 2044 (4.93% effective interest rate)	302,786				302,845
	994,166				993,786
Senior Notes-Private Placement:
4.22% Senior Notes, net of discount, due 2028 (4.31% effective interest rate)	124,205				124,157
Total Senior Notes	1,118,371				1,117,943
RGRT Senior Notes-Private Placement (3):
5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate)	44,969				44,928
4.07% Senior Guaranteed Notes, due 2025 (4.18% effective interest rate)	64,645				64,579
Total RGRT Senior Notes	109,614				109,507
Total long-term debt	1,385,950				1,385,219
Financing Obligations:
Revolving Credit Facility (4)	113,801				49,207
Total long-term debt and financing obligations	1,499,751				1,434,426
Current Portion (amount due within one year):
Current maturities of long term debt (1)(3)	( 44,969		)		( 99,239		)
Short-term borrowings under the revolving credit facility	( 113,801		)		( 49,207		)
	$	1,340,981			$	1,285,980

_____________________

(1)	Pollution Control Bonds

The Company has three series of tax exempt unsecured PCBs in aggregate principal amount of $ 159.8 million as of December 31, 2019. The 2009 Series A 7.25 % and the 2009 Series B 7.25 % PCBs with an aggregate principal amount, together, of $ 100.6 million had optional redemptions beginning in February 2019 and April 2019, respectively. The principal and related unamortized issuance cost on these PCBs were classified as current maturities of long-term debt as of December 31, 2018.

The Company purchased in lieu of redemption all of the 2009 Series A 7.25 % PCBs with an aggregate principal amount of $ 63.5 million , and all of the 2009 Series B 7.25 % PCBs with an aggregate principal amount of $ 37.1 million , on February 1, 2019 and April 1, 2019, respectively, utilizing funds borrowed under the RCF.

On May 22, 2019, the Company reoffered and sold $ 63.5 million aggregate principal amount of 2009 Series A 7.25 % PCBs and $ 37.1 million aggregate principal amount of 2009 Series B 7.25 % PCBs with a fixed interest rate of 3.60 % per annum

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until the PCBs mature on February 1, 2040 and April 1, 2040, respectively. The PCBs are subject to optional redemption at a redemption price of par on or after June 1, 2029. Proceeds from the remarketing of the PCBs were primarily used to repay outstanding short-term borrowings under the RCF.

(2)	Senior Notes

The Senior Notes are unsecured obligations of the Company. They were issued pursuant to bond covenants that provide limitations on the Company’s ability to enter into certain transactions. The 6.00 % Senior Notes have an aggregate principal amount of $ 400.0 million and were issued in May 2005. The proceeds, net of a $ 2.3 million discount, were used to fund the retirement of the Company's first mortgage bonds. The Company amortizes the loss associated with a cash flow hedge recorded in AOCI to earnings as interest expense over the life of the 6.00 % Senior Notes. See Part II, Item 8, Financial Statements and Supplementary Data, Note Q of Notes to Financial Statements. This amortization is included in the effective interest rate of the 6.00 % Senior Notes.

The 7.50 % Senior Notes have an aggregate principal amount of $ 150.0 million and were issued in June 2008. The proceeds, net of a $ 1.3 million discount, were used to repay outstanding short-term borrowings of $ 44.0 million , fund capital expenditures and for other general corporate purposes.

The 3.30 % Senior Notes have an aggregate principal amount of $ 150.0 million were issued in December 2012. The proceeds, net of a $ 0.3 million discount, were used to repay outstanding short-term borrowings, fund construction expenditures and for working capital and general corporate purposes.

In December 2014, the Company issued 5.00 % Senior Notes with an aggregate principal amount of $ 150.0 million . The proceeds, net of a $ 0.5 million discount, were used to fund construction expenditures and for working capital and general corporate purposes. In March 2016, the Company issued additional 5.00 % Senior Notes with an aggregate principal amount of $ 150.0 million . The proceeds from this issuance, after deducting the underwriters' commission, were $ 158.1 million . These proceeds included accrued interest of $ 2.4 million and a $ 7.1 million premium before expenses. The net proceeds from the sale of these senior notes were used to repay outstanding short-term borrowings under the RCF. After the March 2016 issuance, the Company's 5.00 % Senior Notes due 2044 had a total principal amount outstanding of $ 300.0 million .

On June 28, 2018, the Company entered into a note purchase agreement with several institutional purchasers under which the Company issued and sold $ 125.0 million aggregate principal amount of 4.22 % Senior Notes due August 15, 2028. The net proceeds from the issuance of these senior notes were used to repay outstanding short-term borrowings under the RCF for working capital and general corporate purposes. The Company pays interest on the notes semi-annually on February 15 and August 15 of each year until maturity, beginning on February 15, 2019. The Company may redeem the notes, in whole or in part, at any time at a redemption price equal to 100 % of the principal amount to be redeemed together with the interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on the prevailing market interest rates. The issuance and sale of these senior notes was made in reliance on a private placement exemption from the registration provisions of the Securities Act of 1933, as amended (the "Securities Act").

(3)	RGRT Senior Notes

In 2010, the Company and RGRT, a Texas grantor trust through which the Company finances its portion of fuel for Palo Verde, entered into a note purchase agreement with various institutional purchasers. Under the terms of the agreement, RGRT issued and sold to the purchasers $ 110.0 million aggregate principal amount of Senior Notes ("RGRT Notes"). In August 2015 and 2017, $ 15.0 million and $ 50.0 million of the RGRT Notes, respectively, matured and were paid with borrowings from the RCF. The Company guarantees the payment of principal and interest on the RGRT Notes. In the Company’s financial statements, the assets and liabilities of RGRT are reported as assets and liabilities of the Company. In August 2020, the remaining $ 45.0 million of these RGRT Notes mature.

The sale of the RGRT Notes was made by RGRT in reliance on a private placement exemption from registration under the Securities Act. The proceeds of $ 109.4 million , net of issuance costs, from the sale of the RGRT Notes was used by RGRT to repay amounts borrowed under the RCF and enabled future nuclear fuel financing requirements of RGRT to be met with a combination of the RGRT Notes and amounts borrowed from the RCF.

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On June 28, 2018, the RGRT and the Company entered into a note purchase agreement with several institutional purchasers under which the RGRT issued and sold $ 65.0 million aggregate principal amount of 4.07 % Senior Guaranteed Notes due August 15, 2025 ("RGRT Senior Notes"). The net proceeds from the RGRT Senior Notes were used to repay outstanding short-term borrowings under the RCF to finance nuclear fuel purchases. The Company guaranteed the payment of principal and interest on the RGRT Senior Notes. RGRT’s assets, liabilities and operations are consolidated in the Company’s financial statements and the RGRT Senior Notes are included as long-term debt on the balance sheet. The issuance and sale of the RGRT Senior Notes was made in reliance on a private placement exemption from the registration provisions of the Securities Act.

RGRT pays interest on the senior notes above on February 15 and August 15 of each year until maturity, beginning on February 15, 2019. RGRT may redeem the senior notes, in whole or in part, at any time at a redemption price equal to 100 % of the principal amount to be redeemed together with the interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on the prevailing market interest rates.

(4)	Revolving Credit Facility

On January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the RCF with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication agent, and various lending banks party thereto. As of December 31, 2016, the Company had available $ 300.0 million and the ability to increase the RCF by up to $ 100.0 million with a term ending January 2019. On January 9, 2017, the Company exercised its option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $ 50.0 million to $ 350.0 million .

On September 13, 2018, the Company and The Bank of New York Mellon Trust Company, N.A., as trustee of the RGRT, entered into a third amended and restated credit agreement ("RCF Agreement") with MUFG Union Bank, N.A., as administrative agent and as syndication agent, various issuing banks and lending banks party thereto. Under the terms of the RCF Agreement, the Company has available a $ 350.0 million RCF with a $ 50.0 million subfacility for the issuance of letters of credit, and the Company extended the term of the Company's existing $ 350.0 million revolving credit agreement from January 14, 2020 to September 13, 2023 ("Maturity Date"). The Company may increase the RCF by up to $ 50.0 million (to a total of $ 400.0 million ) during the term of the RCF Agreement, upon the satisfaction of certain conditions more fully set forth in the RCF Agreement, including obtaining commitments from lenders or third party financial institutions. In addition, the Company may extend the Maturity Date up to two times, in each case for an additional one year period, upon the satisfaction of certain conditions more fully set forth in the RCF Agreement, including requisite lender approval.

The RCF Agreement provides that amounts borrowed by the Company may be used for, among other things, working capital

and general corporate purposes. Any amounts borrowed by the RGRT may be used, among other things, to finance the acquisition and cost to process nuclear fuel. Amounts borrowed by the RGRT are guaranteed by the Company and the balance borrowed under the RCF Agreement is recorded as short-term borrowings on the balance sheet. The RCF Agreement is unsecured. In August 2017, $ 50.0 million aggregate principal amount of Series B 4.47 % Senior Notes of the RGRT matured and was paid with borrowings from the RCF. On February 1, 2019 and April 1, 2019, respectively, the Company purchased in lieu of redemption all of the 2009 Series A 7.25 % PCBs with a principal amount of $ 63.5 million and 2009 Series B 7.25 % PCBs with a principal amount of $ 37.1 million , utilizing funds borrowed under the RCF. On May 22, 2019, the Company reoffered and sold $ 63.5 million aggregate principal amount of 2009 Series A 7.25 % PCBs and $ 37.1 million aggregate principal amount of 2009 Series B 7.25 % PCBs. The proceeds from the remarketing of the PCBs were principally used to repay outstanding short-term borrowings under the RCF. As of December 31, 2019 , the total amount borrowed by the RGRT was $ 29.8 million for nuclear fuel under the RCF. As of December 31, 2019 , $ 84.0 million of borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 3.0 % as of December 31, 2019 , with an additional $ 236.0 million available to borrow.

The Merger would constitute a "Change in Control" under the RCF and the consummation of the Merger would result in an event of default under the RCF. On and subject to the terms and conditions of the Merger Agreement, the Company requested that the lenders under the RCF consent to the Merger and waive any default or event of default that would occur as a result of the Merger. On August 9, 2019, the lenders agreed to such consent and waiver.

Under the Merger Agreement, subject to certain exceptions, the Company cannot incur additional indebtedness over $ 200.0 million (excluding borrowings up to the existing borrowing capacity of the RCF), without the prior written consent of Parent.

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As of December 31, 2019 , the principal amount of scheduled maturities for the next five years of long-term debt are as follows (in thousands):

2020	$	45,000
2021	—
2022	150,000
2023	—
2024	—

Pursuant to the Company’s debt agreements, the Company is required to comply with various covenants and restrictions, including a total debt to capitalization ratio as required by each one of the Company’s and RGRT’s private placement debt securities and the RCF. The Company is in compliance with all of its debt covenants and restrictions.

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The Company’s lease population is composed of operating leases. The Company leases land in El Paso, Texas, adjacent to Newman under a lease that expires in June 2033 with a renewal option of 25 years . The Company also has several other leases for offices, parking facilities and equipment that expire within the next 5 years , including an office in Austin, Texas. The Company has transmission and distribution lines that are operated under various land rights agreements, including easements, leases, permits and franchises. The components of lease expense are as follows:

	Year Ended
	December 31, 2019
Lease cost (in thousands):
Operating lease cost	$	1,012
Short-term lease cost	798
Variable lease cost	65
Total lease cost	$	1,875

Supplemental balance sheet information related to leases was as follows (in thousands, except lease term and discount rate):

	December 31, 2019
Operating leases:
Operating lease ROU assets (included in electric plant in service)	$	5,550
Operating lease liabilities (current included in other current liabilities)	513
Operating lease liabilities (net of current included in deferred credits and other liabilities)	5,094
Total lease liabilities	$	5,607
Weighted average remaining lease terms (in years)	11.91
Weighted average discount rate	4.66		%

Supplemental cash flow information related to leases was as follows (in thousands):

	Year Ended
	December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows used for operating leases	$	897

ROU assets obtained in exchange for lease obligations (in thousands):

	Year Ended
	December 31, 2019
Operating leases	$	5,550

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Maturities of operating lease liabilities at December 31, 2019 were as follows (in thousands):

Year ending December 31,
2020	$	751
2021	676
2022	619
2023	571
2024	559
Thereafter	4,126
Total lease payments	7,302
Less imputed interest	( 1,695		)
Total	$	5,607

Disclosures related to periods prior to adoption of the new lease standard

The Company’s total rental expense related to operating leases was $ 1.7 million and $ 2.4 million for the twelve months ended December 31, 2018 and 2017, respectively. As of December 31, 2018, the Company’s minimum future rental payments for the next five years were as follows (in thousands):

Year ending December 31,
2019	$	923
2020	820
2021	700
2022	544
2023	526

On December 22, 2017, the TCJA was enacted. The TCJA includes significant changes to the Internal Revenue Code of 1986, including amendments that significantly changed the taxation of business entities and includes specific provisions related to regulated public utilities. The more significant changes that impact the Company included in the TCJA are reductions in the federal corporate income tax rate from 35 % to 21 % , elimination of the corporate alternative minimum tax provision, additional limitations on deductions of executive compensation, and limitations on the utilization of NOLs arising after December 31, 2017, to 80 % of taxable income with no carryback but with an indefinite carryforward. The specific provisions related to regulated public utilities in the TCJA generally provide for the continued deductibility of interest expense, the elimination of bonus depreciation for property acquired and placed into service after December 31, 2017, and the continuance of rate normalization requirements for accelerated depreciation benefits and changes to deferred tax balances as a result of the change in the federal corporate income tax rate. Although the Company recorded provisional estimates of the impact of the TCJA, as of the date of enactment, no significant subsequent adjustments to the provisional estimates were recorded during the one-year measurement period as permitted by the U.S. Securities and Exchange Commission ("SEC") in Staff Accounting Bulletin No. 118.

Reductions in accumulated deferred federal income taxes due to the reduction in the corporate income tax rate to 21 % under the provisions of the TCJA will result in amounts previously collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The TCJA includes provisions that stipulate how these excess deferred taxes are to be returned to customers for certain accelerated tax depreciation benefits. Potential refunds of other excess deferred taxes will be determined by the Company’s regulators.

In February 2018, the FASB issued ASU 2018-02, which addresses concerns that the tax reduction due to the change in the corporate tax rate from 35 % to 21 % would be "stranded" in AOCI. ASU 2018-02 allows companies an election to reclassify stranded taxes from AOCI to retained earnings. The Company adopted ASU 2018-02 on January 1, 2019, and elected to not reclassify stranded taxes from AOCI to retain earnings. See Part II, Item 8, Financial Statements and Supplementary Data, Note B of Notes to Financial Statements for further discussion on new accounting standards.

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The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2019 and 2018 are presented below (in thousands):

	December 31,
	2019				2018
Deferred tax assets:
Benefit of tax loss carryforwards	$	—			$	12,521
Alternative minimum tax credit carryforward	—				8,855
Pensions and benefits	33,456				31,874
Asset retirement obligations	23,239				21,305
Regulatory liabilities related to income taxes	63,103				63,378
Deferred fuel	4,124				2,483
Other	—				2,673
Total gross deferred tax assets	123,922				143,089
Deferred tax liabilities:
Plant, principally related to depreciation and basis differences	( 432,073		)		( 437,465		)
Decommissioning	( 39,737		)		( 30,757		)
Other	( 510		)		—
Total gross deferred tax liabilities	( 472,320		)		( 468,222		)
Net accumulated deferred income taxes	$	( 348,398	)		$	( 325,133	)

As of December 31, 2019 , the Company had fully utilized all alternative minimum tax credit carryforwards and all other tax loss and credit carryforwards. Based on the average annual earnings before taxes for the prior three years , and excluding the effects of unusual or infrequent items, the Company believes that the deferred tax assets will be fully realized.

The Company recognized income tax expense for 2019 , 2018 and 2017 as follows (in thousands):

	Years Ended December 31,
	2019				2018				2017
Income tax expense (benefit):
Federal:
Current	$	4,827			$	( 4,638	)		$	2,507
Deferred	28,637				24,121				46,089
Total federal income tax	33,464				19,483				48,596
State:
Current	2,061				1,888				( 897		)
Deferred	( 744		)		1,941				1,816
Total state income tax	1,317				3,829				919
Generation (amortization) of accumulated investment tax credits	( 750		)		3,056				1,489
Total income tax expense	$	34,031			$	26,368			$	51,004

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Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 21 % in 2019 and 2018, and 35 % in 2017 to book income before federal income tax as follows (in thousands):

	Years Ended December 31,
	2019				2018				2017
Federal income tax expense computed on income at statutory rate	$	32,984			$	23,243			$	52,243
Difference due to:
State taxes, net of federal benefit	1,041				3,059				597
Permanent tax differences	( 1,405		)		( 682		)		( 2,562		)
Other	1,411				748				726
Total income tax expense	$	34,031			$	26,368			$	51,004
Effective income tax rate	21.7		%		23.8		%		34.2		%

The Company files income tax returns in the U.S. federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal, Arizona and New Mexico jurisdictions for years prior to 2015. In August 2017, the Company reached an agreement with the Texas Comptroller of Public Accounts and settled audits in Texas for tax years 2007 through 2011 .

The FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company recorded a decrease of $ 0.4 million , and a decrease of $ 1.2 million (net of an increase of $ 0.5 million ), in 2019 and 2017, respectively, related to transmission and distribution costs and other amounts deducted in current and prior year Texas franchise tax returns. The Company recorded an unrecognized tax position of $ 0.3 million , $ 0.5 million , and $ 0.1 million in 2019, 2018 and 2017, respectively, related to tax credits taken and apportionment factors used in prior year Arizona income tax returns, which have been settled through audit. A reconciliation of the December 31, 2019 , 2018 and 2017 amounts of unrecognized tax benefits are as follows (in thousands):

	2019				2018				2017
Balance at January 1	$	4,700			$	4,200			$	5,300
Additions for tax positions related to the current year	—				—				200
Reductions for tax positions related to the current year	—				( 200		)		—
Additions for tax positions of prior years	400				700				400
Reductions for tax positions of prior years	( 500		)		—				( 1,700		)
Balance at December 31	$	4,600			$	4,700			$	4,200

If recognized, $ 1.9 million of the unrecognized tax position at December 31, 2019 , would reduce the effective tax rate. The Company recognized an income tax benefit for the decrease in unrecognized tax positions of $ 0.3 million for the year ended December 31, 2019 .

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Power Purchase and Sale Contracts

To supplement its own generation and operating reserve requirements and to meet its 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. On November 18, 2019, the Company filed for regulatory approval with the NMPRC for three power purchase agreements relating to both solar and battery storage resources as a result of the Company's 2017 All Source Request for Proposal for Electric Power Supply and Load Management Resources. The three power purchase agreements filed for approval with the NMPRC included: (i) a 100 MW solar plant to be constructed in Santa Teresa, New Mexico; (ii) a 100 MW solar plant combined with a 50 MW battery energy storage to be constructed in Otero County, New Mexico; and (iii) a 50 MW battery energy storage facility to be constructed in Canutillo, Texas. These projects are contingent upon written approval from the NMPRC. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further discussion. The Company has entered into the following significant agreements with various counterparties for the purchase and sale of electricity:

										Commercial
										Operation
Type of Contract		Counterparty		Quantity				Term		Date
Power Purchase and Sale Agreement		Freeport			25	MW		December 2008 through December 2021		N/A
Power Purchase and Sale Agreement		Freeport			100	MW		June 2006 through December 2021		N/A
Power Purchase Agreement		Hatch Solar Energy Center I, LLC			5	MW		July 2011 through July 2036		July 2011
Power Purchase Agreement		Solar Roadrunner, LLC			20	MW		August 2011 through August 2031		August 2011
Power Purchase Agreement		SunE EPE1, LLC			10	MW		June 2012 through June 2037		June 2012
Power Purchase Agreement		SunE EPE2, LLC			12	MW		May 2012 through May 2037		May 2012
Power Purchase Agreement		Macho Springs Solar, LLC			50	MW		May 2014 through May 2034		May 2014
Power Purchase Agreement		Newman Solar LLC			10	MW		December 2014 through December 2044		December 2014

The Company has a firm 100 MW Power Purchase and Sale Agreement ("Power Purchase and Sale Agreement") with Freeport-McMoRan Copper & Gold Energy Services LLC ("Freeport") that provides for Freeport to deliver energy to the Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase the quantities noted in the table above at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. The agreement was approved by the FERC and will continue through an initial term ending December 31, 2021 , with subsequent rollovers until terminated. Upon mutual agreement, the Power Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold under the agreement. The parties have agreed to increase the amount up to 125 MW through December 2021.

The Company has entered into several power purchase agreements to help meet its RPS requirements. Namely, the Company has a 25 -year purchase power agreement with Hatch Solar Energy Center I, LLC to purchase all of the output from a solar photovoltaic plant located in southern New Mexico, which began commercial operation in July 2011. In June 2015, the Company entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement photovoltaic modules. The Company also entered into a 20 -year contract with Solar Roadrunner, LLC, a subsidiary of Global Infrastructure Partners, (formerly known as NRG Solar Roadrunner LLC) to purchase all of the output of a solar photovoltaic plant built in southern New Mexico, which began commercial operation in August 2011. In addition, the Company has 25 -year purchase power agreements to purchase all of the output of two additional solar photovoltaic plants located in southern New Mexico, SunE EPE1, LLC and SunE EPE2, LLC, which began commercial operation in June 2012 and May 2012 , respectively. In September 2017, Longroad Solar Portfolio Holdings, LLC purchased SunE EPE1, LLC, and in October 2017, Silicon Ranch Corporation purchased SunE EPE2, LLC with the Company's consent per the terms of both 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 plant located in Luna County, New Mexico, which

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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 of approximately 10 MW from a solar photovoltaic plant on land subleased from the Company in proximity to Newman. This solar photovoltaic plant began commercial operation in December 2014 .

Environmental Matters

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

National Ambient Air Quality Standards (" NAAQS ") . Under the U.S. Clean Air Act ("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 (the "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 2018, several petitions for review of the Final Rule were filed in the U.S. Court of Appeals for the District of Columbia Circuit ("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. The case was heard by the D.C. Circuit in November 2019 and a decision regarding the El Paso designation is expected in 2020.

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.

Climate Change. 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"). On August 31, 2018, the EPA published a proposal to replace the CPP called the Affordable Clean Energy ("ACE") rule. The ACE rule was finalized in July 2019. Remaining legal challenges to the CPP were mooted in September 2019, but legal challenges to the ACE rule are ongoing. As adopted, the ACE rule is focused on coal-fired generation and would not impose requirements on our operations. However, at this time the Company cannot determine the impact that the ACE rule and related proposals and legal challenges may have on the Company's financial position, results of operations or cash flows.

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, 2019, the Company has accrued its remaining unpaid share of approximately $ 0.2 million related to this matter.

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Union Matters

The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect on the financial position, results of operations or cash flows of the Company. The Company expenses legal costs, including expenses related to loss contingencies, as they are incurred.

See

Part II, Item 8, Financial Statements and Supplementary Data, Note D and Note M 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.

Litigation Related to the Merger. As of February 26, 2020, three purported Company shareholders have filed lawsuits under the federal securities laws, two in the U.S. District Court for the Southern District of New York and one in the U.S. District Court for the District of Delaware, challenging the adequacy of the disclosures made in the Company’s preliminary proxy statement in connection with the Merger. These cases are captioned Stein v. El Paso Electric Company., et al., Case No. 1:19-cv-06703 in the U.S. District Court for the Southern District of New York (the "Stein Action"), Rosenblatt v. El Paso Electric Company., et al. , Case No. 1:19-cv-01367-UNA in the U.S. District Court for the District of Delaware (the "Rosenblatt Action"), and Gorski v. El Paso Electric Company., et al., Case No. 1:19-cv-07211 in the U.S. District Court for the Southern District of New York (the "Gorski Action"), respectively. The Stein Action, filed on July 18, 2019, the Rosenblatt Action, filed on July 23, 2019, and the Gorski Action, filed on August 1, 2019, are asserted on behalf of putative classes of Company shareholders.

All three actions allege violations of Sections 14(a) and 20(a) of the Securities and Exchange Act of 1934, as amended (the "Exchange Act") and Rule 14a-9 promulgated thereunder based on various alleged omissions of material information from the preliminary proxy statement. The Stein Action names as defendants the Company and each of our directors, individually, and seeks to enjoin the Merger (or, in the alternative, rescission or an award of rescissory damages in the event the Merger is completed), damages, and an award of costs and attorneys’ and expert fees. The Rosenblatt Action names as defendants the Company and each of our directors, individually, and seeks to enjoin the Merger (or, in the alternative, rescission or an award of rescissory damages in the event the Merger is completed), to compel our directors to issue a revised proxy statement, a declaration that the defendants violated Sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9 promulgated thereunder, and an award of costs and attorneys’ and expert fees. The Gorski Action also names as defendants the Company and each of our directors, individually, and seeks to enjoin the Merger (or, in the alternative, rescission or an award of rescissory damages in the event the Merger is completed), to compel our directors to issue a revised proxy statement, a declaration that the defendants violated Sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9 promulgated thereunder, and an award of costs and attorneys’ and expert fees.

The Company believes that these complaints are without merit, and while the Company believes that the disclosures set forth in the proxy statement complied fully with applicable law, to moot plaintiffs’ disclosure claims, to avoid nuisance, potential expense and delay, and to provide additional information to the Company’s shareholders, the Company voluntarily supplemented the proxy statement with additional disclosure in a Current Report on Form 8-K filed by the Company with the SEC on September 9, 2019. While the outcome of these matters cannot be predicted with certainty, based upon a review of the matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect on the financial position, results of operations or cash flows of the Company. The Company expenses legal costs, including expenses related to loss contingencies, as they are incurred.

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Retirement Plans

The Company’s Retirement Income Plan ("Retirement Plan") is a qualified noncontributory defined benefit plan. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are based on various factors, such as the minimum funding amounts required by the U.S. Internal Revenue Service, state and federal regulatory requirements, amounts requested from customers in the Company's Texas and New Mexico jurisdictions, and the annual net periodic benefit cost of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are primarily invested in common collective trusts which hold equity securities, debt securities and cash equivalents and are managed by a professional investment manager appointed by the Company.

The Company has two non-qualified retirement plans that are non-funded defined benefit plans. The Company's Supplemental Retirement Plan covers certain former employees and directors of the Company. The Excess Benefit Plan was adopted in 2004 and covers certain active and former employees of the Company. The net periodic benefit cost for the non-qualified retirement plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.

The Retirement Plan was amended effective April 1, 2014 to offer a cash balance pension benefit as an alternative to its existing final average pay pension benefit for employees hired prior to January 1, 2014 . Employees hired after January 1, 2014 are automatically enrolled in the cash balance pension benefit.

Prior to December 31, 2013 , employees who completed one year of service with the Company and worked at least a minimum number of hours each year were covered by the final average pay formula of the plan. For participants that continue to be covered by the final average pay formula, retirement benefits are based on the employee’s final average pay and years of service. The cash balance pension benefit covers employees beginning on their employment commencement date or re-employment commencement date. Retirement benefits under the cash balance pension benefit are based on the employee’s cash balance account, consisting of pay credits and interest credits.

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The obligations and funded status of the plans are presented below (in thousands):

	December 31,
	2019								2018
	Retirement Income Plan				Non-Qualified Retirement Plans				Retirement Income Plan				Non-Qualified Retirement Plans
Change in projected benefit obligation:
Benefit obligation at end of prior year	$	335,496			$	26,719			$	361,989			$	28,392
Service cost	8,127				415				9,086				480
Interest cost	13,451				1,003				12,013				865
Actuarial (gain) loss	56,988				1,624				( 29,911		)		( 1,087		)
Benefits paid	( 15,955		)		( 1,940		)		( 17,681		)		( 1,931		)
Benefit obligation at end of year	398,107				27,821				335,496				26,719
Change in plan assets:
Fair value of plan assets at end of prior year	272,803				—				304,389				—
Actual return (loss) on plan assets	64,368				—				( 19,683		)		—
Employer contribution	7,300				1,940				7,300				1,931
Benefits paid	( 15,955		)		( 1,940		)		( 17,681		)		( 1,931		)
Administrative and investment expenses	( 1,364		)		—				( 1,522		)		—
Fair value of plan assets at end of year	327,152				—				272,803				—
Funded status at end of year	$	( 70,955	)		$	( 27,821	)		$	( 62,693	)		$	( 26,719	)

Amounts recognized in the Company's balance sheets consist of the following (in thousands):

	December 31,
	2019								2018
	Retirement Income Plan				Non-Qualified Retirement Plans				Retirement Income Plan				Non-Qualified Retirement Plans
Current liabilities	$	—			$	( 2,031	)		$	—			$	( 2,153	)
Noncurrent liabilities	( 70,955		)		( 25,790		)		( 62,693		)		( 24,566		)
Total	$	( 70,955	)		$	( 27,821	)		$	( 62,693	)		$	( 26,719	)

The accumulated benefit obligation in excess of plan assets is as follows (in thousands):

	December 31,
	2019								2018
	Retirement Income Plan				Non-Qualified Retirement Plans				Retirement Income Plan				Non-Qualified Retirement Plans
Projected benefit obligation	$	( 398,107	)		$	( 27,821	)		$	( 335,496	)		$	( 26,719	)
Accumulated benefit obligation	( 364,941		)		( 26,413		)		( 308,582		)		( 24,251		)
Fair value of plan assets	327,152				—				272,803				—

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Pre-tax amounts recognized in AOCI consist of the following (in thousands):

	Years Ended December 31,
	2019								2018
	Retirement Income Plan				Non-Qualified Retirement Plans				Retirement Income Plan				Non-Qualified Retirement Plans
Net loss	$	121,622			$	10,153			$	112,532			$	9,300
Prior service benefit	( 13,475		)		( 68		)		( 16,942		)		( 107		)
Total	$	108,147			$	10,085			$	95,590			$	9,193

The following are the weighted-average actuarial assumptions used to determine the benefit obligations:

	December 31,
	2019									2018
				Non-Qualified									Non-Qualified
	Retirement Income Plan			Supplemental Retirement Plan			Excess Benefit Plan			Retirement Income Plan			Supplemental Retirement Plan			Excess Benefit Plan
Discount rate	3.32	%		2.87	%		3.31	%		4.42	%		4.11	%		4.45	%
Rate of compensation increase	4.5	%		N/A			4.5	%		4.5	%		N/A			4.5	%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed and updated at each measurement date. The discount rate used to measure the fiscal year end obligation is based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1 % increase in the discount rate would decrease the December 31, 2019 retirement plans' projected benefit obligation by 12.2 % . A 1 % decrease in the discount rate would increase the December 31, 2019 retirement plans' projected benefit obligation by 15.2 % .

The components of net periodic benefit cost are presented below (in thousands):

	Years Ended December 31,
	2019								2018								2017
	Retirement Income Plan				Non-Qualified Retirement Plans				Retirement Income Plan				Non-Qualified Retirement Plans				Retirement Income Plan				Non-Qualified Retirement Plans
Service cost (a)	$	9,491			$	415			$	10,608			$	480			$	8,156			$	362
Interest cost	13,451				1,003				12,013				865				12,196				863
Expected return on plan assets	( 21,492		)		—				( 21,076		)		—				( 19,189		)		—
Amortization of:
Net loss	5,022				770				7,531				1,022				7,572				882
Prior service benefit	( 3,467		)		( 39		)		( 3,467		)		( 39		)		( 3,467		)		( 39		)
Net periodic benefit cost	$	3,005			$	2,149			$	5,609			$	2,328			$	5,268			$	2,068

_____________________

(a) Service cost for the Retirement Plan for 2019 and 2018 includes expenses of $ 1.4 million and $ 1.5 million , respectively, for administrative and investment expenses paid from plan assets during the year.

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The changes in benefit obligations and plan assets recognized in other comprehensive income are presented below (in thousands):

	Years Ended December 31,
	2019								2018								2017
	Retirement Income Plan				Non-Qualified Retirement Plans				Retirement Income Plan				Non-Qualified Retirement Plans				Retirement Income Plan				Non-Qualified Retirement Plans
Net (gain) loss	$	14,112			$	1,624			$	10,848			$	( 1,087	)		$	( 4,265	)		$	2,217
Amortization of:
Net loss	( 5,022		)		( 770		)		( 7,531		)		( 1,022		)		( 7,572		)		( 882		)
Prior service benefit	3,467				39				3,467				39				3,467				39
Total recognized in other comprehensive income	$	12,557			$	893			$	6,784			$	( 2,070	)		$	( 8,370	)		$	1,374

The total amount recognized in net periodic benefit costs and other comprehensive income are presented below (in thousands):

	Years Ended December 31,
	2019								2018								2017
	Retirement Income Plan				Non-Qualified Retirement Plans				Retirement Income Plan				Non-Qualified Retirement Plans				Retirement Income Plan				Non-Qualified Retirement Plans
Total recognized in net periodic benefit cost and other comprehensive income	$	15,562			$	3,042			$	12,393			$	258			$	( 3,102	)		$	3,442

The following are amounts in AOCI that are expected to be recognized as components of net periodic benefit cost during 2020 (in thousands):

	Retirement Income Plan				Non-Qualified Retirement Plans
Net loss	$	8,127			$	828
Prior service benefit	( 3,467		)		( 39		)

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31 :

	2019									2018									2017
				Non-Qualified									Non-Qualified									Non-Qualified
	Retirement Income Plan			Supplemental Retirement Plan			Excess Benefit Plan			Retirement Income Plan			Supplemental Retirement Plan			Excess Benefit Plan			Retirement Income Plan			Supplemental Retirement Plan			Excess Benefit Plan
Discount rate
Benefit obligation	4.42	%		4.11	%		4.45	%		3.77	%		3.40	%		3.81	%		4.30	%		3.76	%		4.35	%
Service cost	4.50	%		N/A			4.53	%		3.86	%		N/A			3.89	%		4.51	%		N/A			4.52	%
Interest cost	4.12	%		3.68	%		4.18	%		3.40	%		2.84	%		3.48	%		3.70	%		2.94	%		3.78	%
Expected long-term return on plan assets	7.5	%		N/A			N/A			7.5	%		N/A			N/A			7.0	%		N/A			N/A
Rate of compensation increase	4.5	%		N/A			4.5	%		4.5	%		N/A			4.5	%		4.5	%		N/A			4.5	%

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The Company’s overall expected long-term rate of return on assets is 7.5 % as of January 1, 2020, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. The expected long-term rate of return is based on the weighted average of the expected returns on investments based upon the target asset allocation of the pension fund. The Company’s target allocations for the plan’s assets are presented below:

		December 31, 2019
Equity securities		45.3	%
Fixed income		46.3	%
Alternative investments		8.4	%
Total		100.0	%

The Retirement Plan invests the majority of its plan assets in common collective trusts which includes a diversified portfolio of domestic and international equity securities and fixed income securities. Alternative investments of the Retirement Plan are comprised of a real estate limited partnership, equity securities of real estate companies, primarily in real estate investment trusts and equity securities of listed companies involved in infrastructure activities. The expected rate of returns for the funds are assessed annually and are based on long-term relationships among major asset classes and the level of incremental returns that can be earned by the successful implementation of different active investment management strategies. Equity, real estate equity and infrastructure equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash, an expected equity risk premium, as well as other economic factors. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads. These assumptions also capture the expected correlation of returns between these asset classes over the long term.

The FASB guidance on disclosure for pension plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements, the FASB guidance on fair value measurements established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•

Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices of securities held in the mutual funds and underlying portfolios of the Retirement Plan are primarily obtained from independent pricing services. These prices are based on observable market data. The Common Collective Trusts are valued using the Net Asset Value ("NAV") provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. The NAV used for determining the fair value of the investments in the Common Collective Trusts have readily determinable fair values. Accordingly, such fund values are categorized as Level 1.

•	Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of these investments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

•	Level 3 – Unobservable inputs using data that is not corroborated by market data.

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The fair value of the Company’s Retirement Plan assets at December 31, 2019 and 2018 , and the level within the three levels of the fair value hierarchy defined by the FASB guidance on fair value measurements are presented in the table below (in thousands):

Description of Securities	Fair Value as of December 31, 2019				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	2,622			$	2,622			$	—			$	—
Common Collective Trusts (a)
Equity funds	148,163				148,163				—				—
Fixed income funds	150,439				150,439				—				—
Real asset funds	24,119				24,119				—				—
Total Common Collective Trusts	322,721				322,721				—				—
Limited Partnership Interest in Real Estate (b)	1,809
Total Plan Investments	$	327,152			$	325,343			$	—			$	—

Description of Securities	Fair Value as of December 31, 2018				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	1,911			$	1,911			$	—			$	—
Common Collective Trusts (a)
Equity funds	140,214				140,214				—				—
Fixed income funds	110,333				110,333				—				—
Real asset funds	16,990				16,990				—				—
Total Common Collective Trusts	267,537				267,537				—				—
Limited Partnership Interest in Real Estate (b)	3,355
Total Plan Investments	$	272,803			$	269,448			$	—			$	—

_____________________

(a)	The Common Collective Trusts are invested in equity and fixed income securities, or a combination thereof. The investment objective of each fund is to produce returns in excess of, or commensurate with, its predefined index.

(b)

This investment is a commercial real estate partnership that purchases land, develops limited infrastructure and sells it for commercial development. The Company was restricted from selling its partnership interest during the life of the partnership, which spanned 7 years . Return on investment is realized as land is sold. The fair value of the limited partnership interest in real estate is based on the NAV of the partnership which reflects the appraised value of the land. The partnership term expired on June 30, 2016 . Upon expiration, dissolution of the partnership commenced and, as a result, the general partner of the partnership is attempting to sell the remaining inventory as soon as possible at the highest pricing possible.

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The table below reflects the changes in the fair value of investments in the real estate limited partnership during the period (in thousands):

	Fair Value of Investments in Real Estate
Balances at December 31, 2017	$	3,853
Sale of land	( 48		)
Unrealized loss in fair value	( 450		)
Balances at December 31, 2018	3,355
Sale of land	( 1,584		)
Unrealized gain in fair value	38
Balances at December 31, 2019	$	1,809

There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable inputs during the twelve-month periods ending December 31, 2019 and 2018 . There were no purchases, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve-month periods ending December 31, 2019 and 2018 .

The Company and the fiduciaries responsible for the Retirement Plan adhere to the traditional capital market pricing theory which maintains that over the long term, the risk of owning equities should be rewarded with a greater return than available from fixed income investments. The Company and the fiduciaries responsible for the Retirement Plan seek to minimize the risk of owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying its investments to limit its risks during falling markets. The investment manager has full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company and the fiduciaries responsible for the Retirement Plan through the plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the Employee Retirement Income Security Act of 1974 ("ERISA") and U.S. Department of Labor ("DOL") regulations.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):

	Retirement Income Plan				Non-Qualified Retirement Plans
2020	$	19,163			$	2,031
2021	19,517				1,995
2022	19,870				1,958
2023	21,462				2,022
2024	21,209				1,949
2025-2029	113,539				8,363

401(k) Defined Contribution Plans

The Company sponsors 401(k) defined contribution plans covering substantially all employees. The Company provides a 50 percent matching contribution up to 6 percent of the employee’s compensation for employees who are enrolled in the final average pay pension benefit of the Retirement Plan and a 100 percent matching contribution up to 6 percent of the employee's compensation for employees who are enrolled in the cash balance pension benefit of the Retirement Plan, subject to certain other limits and exclusions. Annual matching contributions made to the savings plans for the years 2019 , 2018 and 2017 were $ 4.7 million , $ 4.6 million , and $ 4.4 million , respectively.

Other Post-retirement Benefits

The Company provides certain other post-retirement benefits, including health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only ("OPEB Plan"). Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions from the Company are based on various factors such as the OPEB Plan's funded status, tax deductibility of contributions to the OPEB Plan, state and federal regulatory requirements, amounts requested from customers in the Company's Texas and

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New Mexico jurisdictions and the annual net periodic benefit cost of the OPEB Plan, as actuarially calculated. The assets of the OPEB Plan are primarily invested in institutional funds which hold equity securities, debt securities and cash equivalents and are managed by a professional investment manager appointed by the Company.

The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets and the funded status of the OPEB Plan (in thousands):

	December 31,
	2019				2018
Change in benefit obligation:
Benefit obligation at end of prior year	$	60,862			$	67,290
Service cost	2,242				2,591
Interest cost	2,456				2,252
Actuarial (gain) loss	889				( 9,295		)
Benefits paid from plan assets	( 2,643		)		( 3,003		)
Benefits paid from corporate assets	( 176		)		( 141		)
Retiree contributions	1,262				1,168
Benefit obligation at end of year	64,892				60,862
Change in plan assets:
Fair value of plan assets at end of prior year	36,287				40,873
Actual return (loss) on plan assets	6,636				( 2,997		)
Employer contribution	450				450
Benefits paid from plan assets	( 2,643		)		( 3,003		)
Retiree contributions	1,262				1,168
Administrative and investment expenses	( 181		)		( 204		)
Fair value of plan assets at end of year	41,811				36,287
Funded status at end of year	$	( 23,081	)		$	( 24,575	)

Amounts recognized in the Company's balance sheets consist of the following (in thousands):

	December 31,
	2019				2018
Current liabilities	$	—			$	—
Noncurrent liabilities	( 23,081		)		( 24,575		)
Total	$	( 23,081	)		$	( 24,575	)

Pre-tax amounts recognized in AOCI consist of the following (in thousands):

	December 31,
	2019				2018
Net gain	$	( 38,139	)		$	( 36,890	)
Prior service benefit	( 23,472		)		( 28,706		)
Total	$	( 61,611	)		$	( 65,596	)

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The following are the weighted-average actuarial assumptions used to determine the accrued benefit obligations:

	December 31,
	2019			2018
Discount rate at end of year	3.41	%		4.43	%
Health care cost trend rates:
Initial
Pre-65 medical	5.75	%		6.00	%
Post-65 medical	4.50	%		4.50	%
Pre-65 drug	6.75	%		7.00	%
Post-65 drug	7.00	%		8.50	%
Ultimate	4.50	%		4.50	%
Year ultimate reached (a)	2026			2026

_____________________

(a) Pre-65 medical reaches the ultimate trend rate in 2025. Additionally, the Post-65 medical trend is assumed to be 4.50 % for all years into the future.

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed and updated at each measurement date. The discount rate used to measure the fiscal year end obligation is based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1 % increase in the discount rate would decrease the December 31, 2019 accumulated post-retirement benefit obligation by 14.2 % . A 1 % decrease in the discount rate would increase the December 31, 2019 accumulated post-retirement benefit obligation by 18.4 % .

Net periodic benefit cost is made up of the components listed below (in thousands):

	Years Ended December 31,
	2019				2018				2017
Service cost (a)	$	2,423			$	2,795			$	2,236
Interest cost	2,456				2,252				2,723
Expected return on plan assets	( 2,120		)		( 2,435		)		( 1,907		)
Amortization of:
Prior service benefit	( 5,234		)		( 6,151		)		( 6,151		)
Net gain	( 2,377		)		( 2,166		)		( 1,678		)
Net periodic benefit cost	$	( 4,852	)		$	( 5,705	)		$	( 4,777	)

_____________________

(a) Service cost for 2019 and 2018 includes expenses of $ 181 and $ 204 thousand, respectively, for administrative and investment expenses paid from plan assets during the year.

The changes in benefit obligations and plan assets recognized in other comprehensive income are presented below (in thousands):

	Years Ended December 31,
	2019				2018				2017
Net gain	$	( 3,626	)		$	( 3,863	)		$	( 10,586	)
Amortization of:
Prior service benefit	5,234				6,151				6,151
Net gain	2,377				2,166				1,678
Total recognized in other comprehensive income	$	3,985			$	4,454			$	( 2,757	)

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The total amount recognized in net periodic benefit cost and other comprehensive income are presented below (in thousands):

	Years Ended December 31,
	2019				2018				2017
Total recognized in net periodic benefit cost and other comprehensive income	$	( 867	)		$	( 1,251	)		$	( 7,534	)

The amount in AOCI that is expected to be recognized as a component of net periodic benefit cost during 2020 is a prior service benefit of $ 3.1 million and a net gain of $ 2.4 million .

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31 :

	2019			2018			2017
Discount rate:
Benefit obligation	4.44	%		3.79	%		4.37	%
Service cost	4.51	%		3.87	%		4.59	%
Interest cost	4.15	%		3.38	%		3.76	%
Expected long-term return on plan assets	6.00	%		6.12	%		4.875	%
Health care cost trend rates:
Initial
Pre-65 medical	6.0	%		6.25	%		6.5	%
Post-65 medical	4.5	%		4.5	%		4.5	%
Pre-65 drug	7.0	%		7.25	%		7.5	%
Post-65 drug	8.5	%		10.0	%		10.5	%
Ultimate	4.5	%		4.5	%		4.5	%
Year ultimate reached (a)	2026			2026			2026

_____________________

(a) Pre-65 medical reaches the ultimate trend rate in 2025. Additionally, the Post-65 medical trend is assumed to be 4.50 % for all years into the future .

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. The effect of a 1 % change in these assumed health care cost trend rates would increase or decrease the December 31, 2019 benefit obligation by $ 10.6 million or $ 8.3 million , respectively. In addition, a 1 % change in said rate would increase or decrease the aggregate 2019 service and interest cost components of the net periodic benefit cost by $ 1.0 million or $ 0.8 million , respectively.

The Company's overall expected long-term rate of return on assets is 7.85 % , as of January 1, 2020, on a pre-tax basis. The expected long-term rate of return on assets on an after-tax basis is 6.00 % as of January 1, 2020. The trust's tax rate was assumed to be 23.60 % at January 1, 2019 and January 1, 2020. The expected long-term rate of return is based on the after-tax weighted average of the expected returns on investments based upon the target asset allocation. The Company’s target allocations for the plan’s assets are presented below:

		December 31, 2019
Equity securities		45.4	%
Fixed income		39.3	%
Alternative investments		15.3	%
Total		100.0	%

The OPEB Plan invests the majority of its plan assets in institutional funds which includes a diversified portfolio of domestic and international equity securities and fixed income securities. Alternative investments of the OPEB Plan are comprised of a real estate limited partnership and equity securities of real estate companies, primarily in real estate investment

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trusts. The alternative investments also include equity securities of a dynamic, diversified portfolio designed to capture market opportunities. The underlying allocations to various asset classes in this portfolio will shift over time, but the overall strategic allocation is as follows: 75 % global equity, 15 % marketable real assets and 10 % global fixed income. The expected rates of return for the funds are assessed annually and are based on long-term relationships among major asset classes and the level of incremental returns that can be earned by the successful implementation of different active investment management strategies. Equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash, an expected equity risk premium, as well as other economic factors. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads. These assumptions also capture the expected correlation of returns between these asset classes over the long term.

The FASB guidance on disclosure for other post-retirement benefit plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements, the FASB guidance on fair value measurements established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•

Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices of securities held in the mutual funds and underlying portfolios of the Other Post-retirement Benefits Plan are primarily obtained from independent pricing services. These prices are based on observable market data. The institutional funds are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. The NAV used for determining the fair value of the investments in the institutional funds have readily determinable fair values. Accordingly, such fund values are categorized as Level 1.

•	Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of these investments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

•	Level 3 – Unobservable inputs using data that is not corroborated by market data.

---

The fair value of the Company’s OPEB Plan assets at December 31, 2019 and 2018 and the level within the three levels of the fair value hierarchy defined by the FASB guidance on fair value measurements are presented in the table below (in thousands):

Description of Securities	Fair Value as of December 31, 2019				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	2,522			$	2,522			$	—			$	—
Institutional Funds (a)
Equity funds	18,664				18,664				—				—
Fixed income funds	15,038				15,038				—				—
Multi asset funds	3,766				3,766				—				—
Real asset funds	1,482				1,482				—				—
Total Institutional Funds	38,950				38,950				—				—
Limited Partnership Interest in Real Estate (b)	339
Total Plan Investments	$	41,811			$	41,472			$	—			$	—
Description of Securities	Fair Value as of December 31, 2018				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	1,353			$	1,353			$	—			$	—
Institutional Funds (a)
Equity funds	17,887				17,887				—				—
Fixed income funds	11,437				11,437				—				—
Multi asset funds	3,576				3,576				—				—
Real asset funds	1,405				1,405				—				—
Total Institutional Funds	34,305				34,305				—				—
Limited Partnership Interest in Real Estate (b)	629
Total Plan Investments	$	36,287			$	35,658			$	—			$	—

___________________

(a)	The institutional funds are invested in equity or fixed income securities, or a combination thereof. The investment objective of each fund is to produce returns in excess of, or commensurate with, its predefined index.

(b)

This investment is a commercial real estate partnership that purchases land, develops limited infrastructure and sells it for commercial development. The OPEB Plan trust was restricted from selling its partnership interest during the life of the partnership, which spanned 7 years. Return of investment is realized as land is sold. The fair value of the limited partnership interest in real estate is based on the NAV of the partnership which reflects the appraised value of the land. The partnership term expired on June 30, 2016 . Upon expiration, dissolution of the partnership commenced and, as a result, the general partner of the partnership is attempting to sell the remaining inventory as soon as possible at the highest pricing possible.

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The table below reflects the changes in the fair value of the investments in real estate during the period (in thousands):

	Fair Value of Investments  in Real Estate
Balance at December 31, 2017	$	722
Sale of land	( 9		)
Unrealized loss in fair value	( 84		)
Balance at December 31, 2018	629
Sale of land	( 297		)
Unrealized gain in fair value	7
Balance at December 31, 2019	$	339

There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable inputs during the twelve month periods ending December 31, 2019 and 2018 . There were no purchases, issuances and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2019 and 2018 .

The Company and the fiduciaries responsible for the OPEB Plan adhere to the traditional capital market pricing theory, which maintains that over the long term, the risk of owning equities should be rewarded with a greater return than available from fixed income investments. The Company and the fiduciaries responsible for the OPEB Plan seek to minimize the risk of owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying its investments to limit its risks during falling markets. The investment manager has full discretionary authority to direct the investment of plan assets held in trust within the investment policy guidelines prescribed by the Company. The investment guidelines of the investment policy statement are in accordance with the ERISA and DOL regulations.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):

2020	$	2,131
2021	2,277
2022	2,463
2023	2,642
2024	2,843
2025-2029	15,179

Annual Short-Term Incentive Plan

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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. Accordingly, the Company on September 20, 2019, sought approval from the City of El Paso for a deemed assignment of the franchise agreement as a result of the pending Merger, which approval was granted on February 4, 2020. 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

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The FASB guidance requires the Company to disclose estimated fair values for its financial instruments. The Company has determined that cash and temporary investments, investment in debt securities, accounts receivable, decommissioning trust funds, long-term debt, short-term borrowings under the RCF, accounts payable and customer deposits meet the definition of financial instruments. The carrying amounts of cash and temporary investments, accounts receivable, accounts payable and customer deposits approximate fair value because of the short maturity of these items. Investments in debt securities and decommissioning trust funds are carried at estimated fair value.

Long-Term Debt and Short-Term Borrowings Under the RCF. The fair values of the Company's long-term debt and short-term borrowings under the RCF are based on estimated market prices for similar issues and are presented below (in thousands):

	December 31,
	2019								2018
	Carrying Amount				Estimated Fair Value				Carrying Amount				Estimated Fair Value
Pollution Control Bonds (1)	$	157,965			$	167,256			$	157,769			$	161,917
Senior Notes	1,118,371				1,398,645				1,117,943				1,244,310
RGRT Senior Notes (2)	109,614				114,270				109,507				111,440
RCF (2)	113,801				113,801				49,207				49,207
Total	$	1,499,751			$	1,793,972			$	1,434,426			$	1,566,874

__________________

(1)

On February 1, 2019 and April 1, 2019, the Company purchased in lieu of redemption the 2009 Series A 7.25 % PCBs with an aggregate principal amount of $ 63.5 million and the 2009 Series B 7.25 % PCBs with an aggregate principal amount of $ 37.1 million , respectively, utilizing funds borrowed under the RCF. On May 22, 2019, the Company reoffered and sold $ 63.5 million aggregate principal amount of 2009 Series A 7.25 % PCBs and $ 37.1 million aggregate principal amount of 2009 Series B 7.25 % PCBs with a fixed interest rate of 3.60 % per annum until the PCBs mature on February 1, 2040 and April 1, 2040, respectively. See Part II, Item 8, Financial Statements and Supplementary Data, Note J of Notes to Financial Statements for further discussion.

(2)

Nuclear fuel financing, as of December 31, 2019 and December 31, 2018 , is funded through $ 110 million RGRT Senior Notes and $ 29.8 million and $ 26.2 million , respectively, under the RCF. As of December 31, 2019 , $ 84.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2018 , $ 23.0 million was outstanding under the RCF for working capital or general corporate purposes. The interest rate on the Company’s borrowings under the RCF is reset throughout the period reflecting current market rates. Consequently, the carrying value approximates fair value. See Part II, Item 8, Financial Statements and Supplementary Data, Note J of Notes to Financial Statements for further discussion.

Treasury Rate Locks. The Company entered into treasury rate lock agreements in 2005 to hedge against potential movements in the treasury reference interest rate pending the issuance of the 6 % Senior Notes. The treasury rate lock agreements met the criteria for hedge accounting and were designated as a cash flow hedge. In accordance with cash flow hedge accounting, the Company recorded the loss associated with the fair value of the cash flow hedge, net of tax, as a component of accumulated other comprehensive loss and amortizes the accumulated comprehensive loss to earnings as interest expense over the life of the 6 % Senior Notes. In 2020, approximately $ 0.6 million of this accumulated other comprehensive loss item will be reclassified to interest expense.

Contracts and Derivative Accounting. The Company uses commodity contracts to manage its exposure to price and availability risks for fuel purchases and power sales and purchases and these contracts generally have the characteristics of derivatives. The Company does not trade or use these instruments with the objective of earning financial gains on the commodity price fluctuations. The Company has determined that all such contracts outstanding at December 31, 2019 , except for certain natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the "normal purchases and normal sales" exception provided in the FASB guidance for accounting for derivative instruments and hedging activities, and, as such, were not required to be accounted for as derivatives.

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Marketable Securities. The Company’s marketable securities, included in the NDT in the balance sheets, are reported at fair value, which was $ 326.0 million and $ 276.9 million at December 31, 2019 and 2018 , respectively. The investments in the NDT are classified as equity securities and temporary cash and cash equivalents restricted solely for investment in the NDT. These investments are recorded at their estimated fair value in accordance with FASB guidance for certain investments in equity securities. On January 1, 2018, the Company adopted ASU 2016-01, Financial Instruments-Overall, which eliminates the requirements to classify investments in equity securities with readily determinable fair values as trading or available for sale and requires entities to recognize changes in fair value for these securities in net income as reported in the Company's Statements of Operations. ASU 2016-01 requires a modified-retrospective approach and therefore, comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods.

During September 2019, the Company sold all of the fixed income securities classified as available for sale held in the NDT, which approximated 450 individual securities. The proceeds were reinvested in exchange traded funds that hold similar securities. The exchange traded funds meet the definition of equity securities with readily determinable fair values and therefore are not classified as available for sale as of December 31, 2019. Furthermore, changes in the fair value of these exchange traded funds are recorded in net income as reported in the Company's Statements of Operations, as required by ASU 2016-01.

Prior to September 2019, the reported fair values included gross unrealized losses on securities classified as available for sale whose impairment the Company had deemed to be temporary. The table below presents the gross unrealized losses and the fair value of these securities as of December 31, 2018, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position (in thousands):

	December 31, 2018
	Less than 12 Months								12 Months or Longer								Total
	Fair Value				Unrealized Losses				Fair Value				Unrealized Losses				Fair Value				Unrealized Losses
Description of Securities (1) :
Federal Agency Mortgage Backed Securities	$	6,187			$	( 36	)		$	14,567			$	( 510	)		$	20,754			$	( 546	)
U.S. Government Bonds	4,005				( 9		)		36,615				( 1,663		)		40,620				( 1,672		)
Municipal Debt Obligations	3,100				( 74		)		9,037				( 723		)		12,137				( 797		)
Corporate Debt Obligations	22,259				( 763		)		11,231				( 731		)		33,490				( 1,494		)
Total	$	35,551			$	( 882	)		$	71,450			$	( 3,627	)		$	107,001			$	( 4,509	)

______________________

(1)	Includes approximately 156 securities, aggregated by CUSIP number.

Prior to the sale of all the Company's fixed income securities classified as available for sale, the Company monitored the length of time such securities traded below their cost basis along with the amount and percentage of the unrealized loss in determining if a decline in fair value below recorded cost was considered to be other than temporary. In accordance with the FASB guidance, such impairment losses were recognized in net income, and a lower cost basis was established for these securities. The Company does not anticipate expending monies held in the trust before 2044 or a later period when decommissioning of Palo Verde begins. For the twelve months ended December 31, 2019, 2018 and 2017, the Company did not recognize any other than temporary impairment losses on its available for sale securities.

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Investments categorized as available for sale securities also included gross unrealized gains which had not been recognized in the Company's net income prior to September 2019. The table below presents the unrecognized gross unrealized gains and the fair value of these securities, aggregated by investment category as of December 31, 2018 (in thousands):

	December 31, 2018
	Fair Value				Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	9,959			$	176
U.S. Government Bonds	6,987				149
Municipal Debt Obligations	1,952				120
Corporate Debt Obligations	8,283				222
Total Debt Securities	27,181				667

The Company's available for sale securities in the NDT were sold from time to time and the Company used the specific identification basis to determine the amount to reclassify from AOCI into net income. The proceeds from the sale of these securities during the twelve months ended December 31, 2019 , 2018 and 2017 and the related effects on pre-tax income are as follows (in thousands):

	2019				2018				2017
Proceeds from sales or maturities of available-for-sale securities	$	168,177			$	25,955			$	97,037
Gross realized gains included in pre-tax income	$	4,815			$	17			$	11,773
Gross realized losses included in pre-tax income	( 2,583		)		( 1,462		)		( 1,147		)
Net gains (losses) included in pre-tax income	$	2,232			$	( 1,445	)		$	10,626

Upon the adoption of ASU 2016-01, Financial Instruments-Overall, on January 1, 2018, the Company began recording changes in fair market value for equity securities held in the NDT in the Company's Statements of Operations. The unrealized gains and losses recognized during the twelve months ended December 31, 2019 and 2018 and related effects on pre-tax income are as follows (in thousands):

	December 31, 2019				December 31, 2018
Net gains and (losses) recognized on equity securities	$	36,282			$	( 11,522	)
Less: Net gains recognized on equity securities sold	430				7,079
Unrealized gains and (losses) recognized on equity securities still held at reporting date	$	35,852			$	( 18,601	)

Fair Value Measurements. The FASB guidance requires the Company to provide expanded quantitative disclosures for financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company's decommissioning trust investments and investments in debt securities which are included in deferred charges and other assets on the balance sheets. The Company has no liabilities that are measured at fair value on a recurring basis. The FASB guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•

Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial assets utilizing Level 1 inputs include the NDT investments in active exchange-traded equity securities, mutual funds and U.S. Treasury securities that are in a highly liquid and active market. The Institutional Funds - International Equity investments are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets and have readily determinable fair values. Accordingly, such fund values are categorized as Level 1.

•	Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the NDT investments in fixed income securities

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that were sold by the Company in September 2019 and reinvested in similar fixed income securities held in exchange traded funds. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

•	Level 3 – Unobservable inputs using data that is not corroborated by market data and primarily based on internal Company analysis using models and various other analysis. Financial assets utilizing Level 3 inputs are the Company's investment in debt securities.

The securities in the NDT are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. The FASB guidance identifies this valuation technique as the "market approach" with observable inputs. Prior to the sale of all the Company's fixed income securities classified as available for sale in September 2019, the Company analyzed available for sale securities to determine if losses were other than temporary.

The fair value of the NDT and investments in debt securities at December 31, 2019 and 2018 , and the level within the three levels of the fair value hierarchy defined by the FASB guidance are presented in the table below (in thousands):

Description of Securities		Fair Value as  of December 31, 2019				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities		$	1,587			$	—			$	—			$	1,587
Equity Securities:
Domestic (a)		$	295,065			$	295,065			$	—			$	—
International		29,202				29,202				—				—
Total Equity Securities		324,267				324,267				—				—
Cash and Cash Equivalents		1,731				1,731				—				—
Total		$	325,998			$	325,998			$	—			$	—

_________________

(a) Includes $ 148.1 million held in exchange traded funds with underlying investments in debt securities that meet the definition of equity securities with readily determinable fair values.

Description of Securities	Fair Value as  of December 31, 2018				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,656			$	—			$	—			$	1,656
Equity Securities:
Domestic	$	111,325			$	111,325			$	—			$	—
International	24,540				24,540				—				—
Total Equity Securities	135,865				135,865				—				—
Available for sale:
Federal Agency Mortgage Backed Securities	30,713				—				30,713				—
U.S. Government Bonds	47,607				47,607				—				—
Municipal Debt Obligations	14,089				—				14,089				—
Corporate Debt Obligations	41,773				—				41,773				—
Total Available for Sale Debt Securities	134,182				47,607				86,575				—
Cash and Cash Equivalents	6,858				6,858				—				—
Total	$	276,905			$	190,330			$	86,575			$	—

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Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt securities classified as trading securities (in thousands):

	2019				2018
Balance at January 1	$	1,656			$	1,735
Net unrealized losses in fair value recognized in income (a)	( 69		)		( 79		)
Balance at December 31	$	1,587			$	1,656

_____________________

(a) These amounts are reflected in the Company's Statements of Operations as investment and interest income.

There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable inputs during the twelve months ended December 31, 2019 and 2018 . There were no purchases, sales, issuances and settlements related to the assets in the Level 3 fair value measurement category during the twelve months ended December 31, 2019 and 2018 .

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	Years Ended December 31,
	2019				2018				2017
	(In thousands)
Cash paid (refunded) for:
Interest on long-term debt and borrowing under the revolving credit facility	$	70,997			$	70,016			$	70,523
Income tax paid (refunded), net	( 1,451		)		3,546				2,055
Non-cash investing and financing activities:
Changes in accrued plant additions	2,912				1,075				( 5,090		)
Grants of restricted shares of common stock	1,393				1,039				1,171
Issuance of performance shares	2,520				1,499				932
Non-cash operating activities:
Operating lease liabilities arising from obtaining ROU assets	5,550				—				—

The following table summarizes the Company’s unaudited results of operations on a quarterly basis. The quarterly earnings per share amounts for a year will not add to the earnings per share for that year due to the weighting of shares used in calculating per share data.

	2019 Quarters																2018 Quarters
	4th				3rd				2nd				1st				4th				3rd				2nd				1st
									(In thousands except for share data)
Operating revenues (1)	$	190,103			$	294,453			$	203,075			$	174,363			$	190,823			$	300,271			$	236,796			$	175,713
Operating income	13,419				114,027				46,338				4,309				15,113				99,933				53,139				4,044
Net income (loss)	12,942				77,880				26,126				6,089				( 15,285		)		73,271				33,295				( 6,966		)
Basic earnings per share:
Net income (loss)	0.32				1.91				0.64				0.15				( 0.38		)		1.80				0.82				( 0.17		)
Diluted earnings per share:
Net income (loss)	0.32				1.91				0.64				0.15				( 0.38		)		1.79				0.82				( 0.17		)
Dividends declared per share of common stock	0.385				0.385				0.385				0.360				0.360				0.360				0.360				0.335

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(1)	Operating revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations.

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On June 1, 2019, the Company entered into the Merger Agreement, by and among the Company, Parent and Merger Sub. Pursuant to the Merger Agreement, on and subject to the terms and conditions set forth therein, Merger Sub will merge with and into the Company, with the Company continuing as the surviving corporation in the Merger and becoming a wholly owned subsidiary of Parent. Parent and Merger Sub are affiliates of IIF.

On and subject to the terms and conditions set forth in the Merger Agreement, upon the closing of the Merger, each share of common stock including outstanding and unvested restricted stock and unvested performance stock of the Company shall be cancelled and converted into the right to receive $ 68.25 in cash, without interest (the "Merger Consideration").

The Company, Parent and Merger Sub each have made various representations, warranties and covenants in the Merger Agreement. Among other things, the Company has agreed, subject to certain exceptions, to conduct its business in the ordinary course, consistent with past practice, from the date of the Merger Agreement until the closing of the Merger, and not to take certain actions prior to the closing of the Merger without the prior written consent of Parent (which consent shall not be unreasonably withheld, conditioned or delayed). The Company has made certain additional customary covenants, including, subject to certain exceptions: (i) to cause a meeting of the Company’s shareholders to be held to consider approval of the Merger Agreement, (ii) not to solicit proposals relating to alternative business combination transactions and not to participate in discussions concerning, or furnish information in connection with, alternative business combination transactions and (iii) not to withdraw its recommendation to the Company’s shareholders regarding the Merger. In addition, subject to the terms of the Merger Agreement, the Company, Parent and Merger Sub are required to use reasonable best efforts to obtain all required regulatory approvals, which will include clearance under federal antitrust laws and certain approvals by federal and state regulatory bodies, subject to certain exceptions, including that such efforts not result in a Burdensome Condition (as defined in the Merger Agreement). Parent has obtained equity and debt financing commitments for the transactions contemplated by the Merger Agreement, the aggregate proceeds of which will be sufficient to consummate the Merger and the other transactions contemplated by the Merger Agreement, including payment of the aggregate Merger Consideration.

Consummation of the Merger is subject to various conditions, including: (i) approval of the shareholders of the Company, (ii) expiration or termination of the applicable HSR Act waiting period, (iii) receipt of all required regulatory and statutory approvals without the imposition of a Burdensome Condition, (iv) absence of any law or order prohibiting the consummation of the Merger and (v) other customary closing conditions, including (a) subject to materiality qualifiers, the accuracy of each party's representations and warranties, (b) each party's compliance in all material respects with its obligations and covenants under the Merger Agreement and (c) the absence of a material adverse effect with respect to the Company.

The Merger Agreement contains certain termination rights for both the Company and Parent, including if the Merger is not consummated by June 1, 2020 (subject to extension for an additional three months if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Merger Agreement also provides for certain termination rights for each of the Company and Parent, and provides that, upon termination of the Merger Agreement under certain specified circumstances, Parent would be required to pay a termination fee of $ 170 million to the Company, and under other specified circumstances, the Company would be required to pay Parent a termination fee of $ 85 million .

On August 2, 2019, the Company filed a definitive proxy statement with the SEC in connection with the Merger. As of the date of this Annual Report on Form 10-K, three purported Company shareholders have filed lawsuits alleging violations under the federal securities laws, two in the U.S. District Court for the Southern District of New York and one in the U.S. District Court for the District of Delaware, challenging the adequacy of the disclosures made in the Company's proxy statement in connection with the Merger as discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note N of Notes to Financial Statements.

On August 13, 2019, the Company, Parent and IIF US Holding 2 LP, an affiliate of IIF, as applicable, filed (i) the joint report and application for regulatory approvals with the PUCT requesting approval of the Merger pursuant to the PURA, which was assigned PUCT Docket No. 49849, (ii) the joint application for regulatory approvals with the NMPRC requesting approval of the Merger pursuant to the NMPUA and NMPRC Rule 450, which was assigned NMPRC Case No. 19-00234-UT, (iii) the joint application requesting approval of the Merger with the FERC under Section 203 of the Federal Power Act, which was assigned FERC Docket No. EC19-120-000, and (iv) the joint application for regulatory approval for the indirect transfer of the Company’s NRC licenses to Parent from the NRC under the Atomic Energy Act of 1954, which was assigned Docket ID NRC-2019-0214. In addition, on August 13, 2019, the Company and Parent sought the authorization of the FCC to assign or transfer control of the Company’s FCC licenses under FCC File No. 008737430. On December 4, 2019, the Company and Parent received consent from

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the FCC to transfer the Company's FCC licenses.

On August 16, 2019, the Company and Parent filed the notification and report form with the Antitrust Division of the Department of Justice and the FTC under the HSR Act, which was assigned Transaction Identification No. 2019 1858. On September 3, 2019, the Company and Parent received notice from the FTC granting early termination of the waiting period under the HSR Act.

At a special meeting of the Company's shareholders held on September 19, 2019, the Company’s shareholders approved the Merger Agreement and the transactions contemplated thereby, including the Merger, and the compensation that will or may become payable by the Company to its named executive officers in connection with the Merger.

Under the Merger Agreement, the consent to the Merger by the City of El Paso under its franchise agreement with the Company is a condition to the closing of the Merger. Under the franchise agreement, if the City of El Paso does not grant its consent to the Merger, the franchise agreement would terminate upon the closing of the Merger. On September 20, 2019, the Company submitted the Franchise Agreement Assignment Application to the City of El Paso to receive the City's consent to the Merger. On February 4, 2020, the City of El Paso passed Ordinance No. 019022 approving the Franchise Agreement Assignment Application and granting the City of El Paso's consent to the Merger.

On November 21, 2019, the Company and IIF reached an agreement in principle with the PUCT staff and most intervenors regarding the Merger. The PUCT issued an order delaying the hearing on the merits in order to assist in reaching a unanimous settlement. The parties continued discussions and provided an update on the status of settlement at the PUCT meeting on December 13, 2019. A non-unanimous settlement was filed with the PUCT on December 18, 2019, resolving substantially all issues in the application. The hearing at the PUCT on the non-unanimous issues was held on January 7, 2020, at the conclusion of which the PUCT requested the Company and IIF attend the PUCT's January 16, 2020 open meeting to answer any follow-up questions. On January 16, 2020, the PUCT approved the Merger and issued its final order on January 28, 2020.

On January 3, 2020, the Company and IIF filed an unopposed stipulation with the NMPRC regarding the Merger. A hearing at the NMPRC for the unopposed stipulation was held on January 16, 2020. On January 16, 2020, the Hearing Examiner agreed with the consent of parties to waive briefing. On February 12, 2020, the Hearing Examiner issued an Amended Certification of the Stipulation in which it is recommended that the NMPRC approve the unopposed stipulation subject to the parties agreeing to the Hearing Examiner's modifications. A final order is expected in March 2020.

On December 5, 2019, the FERC requested additional information regarding the parties to the Merger. On January 6, 2020, the Company and IIF filed a joint response to FERC's inquiry. On January 17, 2020, the Company and IIF filed a second supplement to the application. The FERC established a January 27, 2020 deadline date for comments on the filings. Several motions to intervene were filed, along with a protest of the January 6, 2020 response. On February 6, 2020, the Company and IIF filed a reply to the January 27, 2020 protest. The joint applications filed with the FERC and the NRC are pending.

Subject to receipt of remaining approvals and satisfaction of the other closing conditions, the Company anticipates that the closing of the Merger will occur in the first half of 2020.

The Company and IIF have agreed to numerous regulatory commitments in connection with the Merger under the agreements with the PUCT, NMPRC, and the City of El Paso discussed above. Among the commitments that will apply to the Company as of the closing of the Merger are the issuance of rate credits to its Texas customers in a total aggregate amount of $ 21 million and to New Mexico customers of $ 8.7 million . Both rate credits will be distributed among customers in 36 monthly installments. The Company will make a tariff filing to implement the rate credit no later than 45 days or 7 days , respectively in Texas and New Mexico, after the closing of the Merger. The Company will not attempt to recover the value of these rate credits in future rate cases.

In connection with the pending Merger, the Company recorded $ 12.1 million of strategic transaction costs, principally related to advisory fees, legal, and other consulting costs, in the twelve months ended December 31, 2019, which are reflected in Other income (deductions) - Strategic transaction costs in the Company's Statements of Operations. The Company will not attempt to recover strategic transaction costs in future rate cases. The Company will reflect any non-deductible amounts in the effective tax rate at the Merger closing date.

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For more information regarding the terms of the Merger, including a copy of the Merger Agreement, see the Company's Current Report on Form 8-K filed with the SEC on June 3, 2019, and its definitive proxy statement relating to the special meeting of shareholders filed with the SEC on August 2, 2019.

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Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Item 9A.	Controls and Procedures

Item 9B.	Other Information

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Item 10.	Directors, Executive Officers of the Registrant and Corporate Governance

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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

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Item 15.	Exhibits and Financial Statement Schedules

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Item 16.	Form 10-K Summary

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