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•	our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;

•	variations in demand for electricity, including those due to weather, seasonality, the general economy, customer and sales growth (or decline), the effects of energy conservation measures and distributed generation, and technological advancements;

•	power plant and transmission system performance and outages;

•	competition in retail and wholesale power markets;

•	regulatory and judicial decisions, developments and proceedings;

•	new legislation, ballot initiatives and regulation, including those relating to environmental requirements, regulatory policy, nuclear plant operations and potential deregulation of retail electric markets;

•	fuel and water supply availability;

•	our ability to achieve timely and adequate rate recovery of our costs, including returns on and of debt and equity capital investment;

•	our ability to meet renewable energy and energy efficiency mandates and recover related costs;

•	risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;

•	current and future economic conditions in Arizona, including in real estate markets;

•	the direct or indirect effect on our facilities or business from cybersecurity threats or intrusions, data security breaches, terrorist attack, physical attack, severe storms, droughts, or other catastrophic events, such as fires, explosions, pandemic health events or similar occurrences;

•	the development of new technologies which may affect electric sales or delivery;

•	the cost of debt and equity capital and the ability to access capital markets when required;

•	environmental, economic and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions;

•	volatile fuel and purchased power costs;

•	the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;

•	the liquidity of wholesale power markets and the use of derivative contracts in our business;

•	potential shortfalls in insurance coverage;

•	new accounting requirements or new interpretations of existing requirements;

•	generation, transmission and distribution facility and system conditions and operating costs;

•	the ability to meet the anticipated future need for additional generation and associated transmission facilities in our region;

•	the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or continue or discontinue power plant operations consistent with our corporate interests; and

•	restrictions on dividends or other provisions in our credit agreements and ACC orders.

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(a)	Up to 60 MW of capacity is available; however, the amount of electricity available to APS under this agreement is based in large part on customer demand and is adjusted annually.

(b)	This is a seasonal capacity exchange agreement under which APS receives electricity during the summer peak season (from May 15 to September 15) and APS returns a like amount of electricity during the winter season (from October 15 to February 15).

(c)	The capacity under this agreement may be increased in 10 MW increments in years 2017 through 2024, up to a maximum of 50 MW.

(d)	Renewable energy purchased power agreements are described in detail below under “Current and Future Resources — Renewable Energy Standard — Renewable Energy Portfolio.”

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(a)	Includes Flagstaff Community Power Project, APS School and Government Program, APS Solar Partner Program, and APS Solar Communities Program.

(b)	Includes rooftop solar facilities owned by third parties. Distributed generation is produced in DC and is converted to AC for reporting purposes.

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Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to, either, authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits.

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On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019 to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.

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Based on an August 21, 2018 D.C. Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations. On November 4, 2019, EPA proposed that all unlined CCR surface impoundments, regardless of their impact (or lack thereof) upon surrounding groundwater, must cease operation and initiate closure by August 31, 2020 (with an optional three-month extension as needed for the completion of alternative disposal capacity).

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On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure. Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations. EPA’s proposal regarding alternative closure would require express EPA authorization for such facilities to continue operating their CCR disposal units under alternative closure.

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•	causing a downgrade of our credit ratings;

•	increasing the cost of future debt financing and refinancing;

•	increasing our vulnerability to adverse economic and industry conditions; and

•	requiring us to dedicate an increased portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future investment in our business or other purposes.

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•	variations in our quarterly operating results;

•	operating results that vary from the expectations of management, securities analysts and investors;

•	changes in expectations as to future financial performance, including financial estimates by securities analysts and investors;

•	developments generally affecting industries in which we operate;

•	announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;

•	announcements by third parties of significant claims or proceedings against us;

•	favorable or adverse regulatory or legislative developments;

•	our dividend policy;

•	future sales by the Company of equity or equity-linked securities; and

•	general domestic and international economic conditions.

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restrictions on our ability to engage in a wide range of “business combination” transactions with an “interested shareholder” (generally, any person who beneficially owns 10% or more of our outstanding voting power, or any of our affiliates or associates who beneficially owned 10% or more of our outstanding voting power at any time during the prior three years) or any affiliate or associate of an interested shareholder, unless specific conditions are met;

•	anti-greenmail provisions of Arizona law and our bylaws that prohibit us from purchasing shares of our voting stock from beneficial owners of more than 5% of our outstanding shares unless specified conditions are satisfied;

•	the ability of the Board of Directors to increase the size of and fill vacancies on the Board of Directors, whether resulting from such increase, or from death, resignation, disqualification or otherwise;

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•	the ability of our Board of Directors to issue additional shares of common stock and shares of preferred stock and to determine the price and, with respect to preferred stock, the other terms, including preferences and voting rights, of those shares without shareholder approval;

•	restrictions that limit the rights of our shareholders to call a special meeting of shareholders; and

•	restrictions regarding the rights of our shareholders to nominate directors or to submit proposals to be considered at shareholder meetings.

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(a)	100% unless otherwise noted.

(b)

Our 29.1% ownership in Palo Verde includes leased interests. See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Nuclear” in Item 1 for details regarding leased interests in Palo Verde.  The other participants are Salt River Project (17.49%), SCE (15.8%), El Paso (15.8%), Public Service Company of New Mexico (10.2%), Southern California Public Power Authority (5.91%), and Los Angeles Department of Water & Power (5.7%).  The plant is operated by APS.

(c)	The other participants are Salt River Project (10%), Public Service Company of New Mexico (13%), Tucson Electric Power Company (7%) and NTEC (7%).  The plant is operated by APS.

(d)	Unit 3 was retired in October 2019 with Units 1 and 2 following in November 2019.

(e)	Ocotillo Steam Units 1 and 2 were retired on January 10, 2019. Units 3 through 7 all went into service on or prior to May 30, 2019 which increased generation capacity by 510 MW.

(f)	Redhawk generation capacity increased by 104 MW following the Advanced Gas Path upgrade installed on both units.

(g)

APS is under contract and currently plans to add battery storage at these AZ Sun sites. Due to the McMicken battery energy storage equipment failure, APS is working with the counterparty for the AZ Sun sites to determine appropriate timing and path forward for such facilities. (See "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Energy Storage" above for details related to these and other energy storage agreements.)

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•	A 2030 target of achieving a resource mix that is 65% clean energy, with 45% of the portfolio coming from renewable energy; and

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•	a test year comprised of twelve months ended June 30, 2019, adjusted as described below;

•	an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•	the following proposed capital structure and costs of capital:

•	a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

•	authorization to defer until APS's next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;

•	a number of proposed rate and program changes for residential customers, including:

▪	a super off-peak period during the winter months for APS’s time-of-use with demand rates;

▪	additional $1.25 million in funding for limited-income crisis bill program; and

▪	a flat bill/subscription rate pilot program;

•	proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;

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•	recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see Note 4 discussion of the 2017 Settlement Agreement); and

•	continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see Note 4 for details related to the resulting regulatory asset).

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•	A decrease of $42 million related to public outreach costs at the parent company primarily associated with the ballot initiative in 2018;

•	A decrease of $28 million in fossil generation costs primarily due to lower planned outages and operating costs, including $4 million of Navajo Plant costs which were offset in depreciation and amortization;

•	A decrease of $19 million related to employee benefit costs;

•	A decrease of $18 million related to costs for renewable energy and similar regulatory programs, which are offset in operating revenues and purchased power;

•	An increase of $12 million for costs related to information technology;

•	An increase of $12 million related to consulting costs; and

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•	A decrease of $3 million for other miscellaneous factors.

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(a)	APS Solar Communities program, energy storage, renewable projects and other clean energy projects

(b)	Primarily information systems and facilities projects

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(a)	The long-term debt matures at various dates through 2049 and bears interest principally at fixed rates.  Interest on variable-rate long-term debt is determined by using average rates at December 31, 2019 (see Note 7).

(b)	See Note 6 for further details.

(c)	Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation (see Notes 4 and 11).

(d)	Contracts to purchase renewable energy credits in compliance with the RES (see Note 4).

(e)	These contractual obligations include commitments for capital expenditures and other obligations.

(f)	Payments to the noncontrolling interests relate to the Palo Verde sale leaseback (see Note 19).

(g)	Commitments relating to purchased power lease contracts are included within the fuel and purchased power commitments line above (see Note 9).

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(a)	Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.

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(a)	Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.

(b)	This assumes a 1% change in the initial and ultimate healthcare cost trend rate.

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(a)

These contracts are economic hedges of our forecasted purchases of natural gas and electricity.  The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.  To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

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•

We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs of recently completed plant and costs deferred as regulatory assets and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•	We evaluated the Company’s disclosures related to regulatory accounting, specifically the impact of rate regulation on the financial statements, including the balances recorded and regulatory developments.

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We read relevant regulatory rate orders issued by the ACC for APS and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the ACC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.

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We read management’s preliminary rate filings submitted and testimony given to the ACC regarding the 2019 Retail Rate Case filed in October 2019 and monitored activity by intervenors, the ACC and its staff. The filing is still under review with the ACC. We read the filing and related testimony to assess the likelihood of recovery in future rates or of a future reduction in rates based on the information available as of our report date.

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We evaluated management’s assessment of the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities based on applicable regulatory orders or precedence set by the ACC under similar circumstances. For certain regulatory assets or liabilities where management’s assessment is based on precedence established by the ACC under similar circumstances and not

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(b)	In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the "Tax Act") on items within accumulated other comprehensive income to retained earnings.

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items within accumulated other comprehensive income to retained earnings.

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Description of Business and Basis of Presentation

 

Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.  APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so.  El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. See Note 11 for more information on 4CA matters.

 

Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries:  APS, El Dorado, BCE and 4CA. APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback.  Intercompany accounts and transactions between the consolidated companies have been eliminated.

 

We consolidate VIEs for which we are the primary beneficiary.  We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE.  In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity.  We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments.  We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities. See Note 19 for additional information.

 

Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.

Accounting Records and Use of Estimates

 

Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America ("GAAP").  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

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Regulatory Accounting

 

APS is regulated by the ACC and FERC.  The accompanying financial statements reflect the rate-making policies of these commissions.  As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies.  Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers.

 

Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction.  This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future.  If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. Management judgments also include assessing the impact of potential Commission-ordered refunds to customers on regulatory liabilities.

 

See Note 4 for additional information.

 

Electric Revenues

 

On January 1, 2018, we adopted new revenue guidance ASU 2014-09, Revenue from contracts with customers; accordingly our 2019 and 2018 electric revenues primarily consist of activities that are classified as revenues from contracts with customers. Our electric revenues generally represent a single performance obligation delivered over time. We have elected to apply the practical expedient that allows us to recognize revenue based on the amount to which we have a right to invoice for services performed.

We derive electric revenues primarily from sales of electricity to our regulated retail customers. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.

 

Revenues from our regulated retail customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase electricity are netted against other contracts to sell electricity. This is called a "book-out" and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

Some of our cost recovery mechanisms are alternative revenue programs.  For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.

See Notes 2 and 4 for additional information.

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Allowance for Doubtful Accounts

 

The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible.  The allowance is calculated by applying an estimated write-off factor to utility revenues.  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 environment.

 

Property, Plant and Equipment

 

Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities.  We report utility plant at its original cost, which includes:

 

•	material and labor;

•	contractor costs;

•	capitalized leases;

•	construction overhead costs (where applicable); and

•	allowance for funds used during construction.

Pinnacle West’s property, plant and equipment included in the December 31, 2019 and 2018 Consolidated Balance Sheets is composed of the following (dollars in thousands):

Property, Plant and Equipment:	2019				2018
Generation	$	8,916,872			$	8,285,514
Transmission	3,095,907				3,033,579
Distribution	6,690,697				6,378,345
General plant	1,132,816				1,039,190
Plant in service and held for future use	19,836,292				18,736,628
Accumulated depreciation and amortization	(6,637,857		)		(6,366,014		)
Net	13,198,435				12,370,614
Construction work in progress	808,133				1,170,062
Palo Verde sale leaseback, net of accumulated depreciation	101,906				105,775
Intangible assets, net of accumulated amortization	290,564				262,902
Nuclear fuel, net of accumulated amortization	123,500				120,217
Total property, plant and equipment	$	14,522,538			$	14,029,570

Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.

We expense the costs of plant outages, major maintenance and routine maintenance as incurred.  We charge retired utility plant to accumulated depreciation.  Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets.  Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset.  See Note 12 for additional information.

 

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APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for asset retirement obligations.  APS believes it is probable it will recover in regulated rates, the costs calculated in accordance with this accounting guidance.

 

We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets.  The approximate remaining average useful lives of our utility property at December 31, 2019 were as follows:

 

•Fossil plant — 17 years;

•Nuclear plant — 22 years;

•Other generation — 21 years;

•Transmission — 40 years;

•Distribution — 34 years; and

•General plant — 8 years.

 

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $522 million in 2019, $486 million in 2018, and $453 million in 2017. For the years 2017 through 2019, the depreciation rates ranged from a low of 0.18% to a high of 24.49%.  The weighted-average depreciation rate was 2.81% in 2019, 2.81% in 2018, and 2.80% in 2017.

Asset Retirement Obligations

APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation assets.  The Palo Verde asset retirement obligation primarily relates to final plant decommissioning.  This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant.  The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal.  These agreements have a history of uninterrupted renewal that APS expects to continue.  As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.

See Note 12 for further information on Asset Retirement Obligations.

Allowance for Funds Used During Construction

 

AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant.  Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income.  Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

 

AFUDC was calculated by using a composite rate of 6.98% for 2019, 7.03% for 2018, and 6.68% for 2017.  APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

 

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Materials and Supplies

 

APS values materials, supplies and fossil fuel inventory using a weighted-average cost method.  APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.

 

Fair Value Measurements

 

We apply recurring fair value measurements to cash equivalents, derivative instruments, investments held in the nuclear decommissioning trust and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans. Due to the short-term nature of short-term borrowings, the carrying values of these instruments approximate fair value.  Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments.  We also disclose fair value information for our long-term debt, which is carried at amortized cost. See Note 7 for additional information.

 

Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date.  Inputs to fair value may include observable and unobservable data.  We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

 

We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available.  When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources.  For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.

 

The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment.  Actual results could differ from the results estimated through application of these methods.

 

See Note 14 for additional information about fair value measurements.

 

Derivative Accounting

 

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates.  We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.  We also enter into derivative instruments for economic hedging purposes.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

 

We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as

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either assets or liabilities.  Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.  See Note 17 for additional information about our derivative instruments.

 

Loss Contingencies and Environmental Liabilities

 

Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business.  Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated.  When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range.  Unless otherwise required by GAAP, legal fees are expensed as incurred.

 

Retirement Plans and Other Postretirement Benefits

 

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries.  We also sponsor another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees.  Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually.  See Note 8 for additional information on pension and other postretirement benefits.

 

Nuclear Fuel

 

APS amortizes nuclear fuel by using the unit-of-production method.  The unit-of-production method is based on actual physical usage.  APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel.  APS then multiplies that rate by the number of thermal units produced within the current period.  This calculation determines the current period nuclear fuel expense.

 

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel.  The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero.  In accordance with a settlement agreement with the DOE in August 2014, we now accrue a receivable and an offsetting regulatory liability through the settlement period ending December of 2019. See Note 11 for information on spent nuclear fuel disposal costs.

 

Income Taxes

 

Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates.  We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis.  In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return.  Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company.  The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures. See Note 5 for additional discussion.

 

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Cash and Cash Equivalents

 

We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition.

The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):

 

	Year ended December 31,
	2019				2018				2017
Cash paid during the period for:
Income taxes, net of refunds	$	12,535			$	21,173			$	2,186
Interest, net of amounts capitalized	218,664				208,479				189,288
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	141,297			$	132,620			$	130,404
Dividends declared but not paid	87,982				82,675				77,667
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	11,262				—				—
Sale of 4CA 7% interest in Four Corners	—				68,907				—

The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):

 

	Year ended December 31,
	2019				2018				2017
Cash paid (received) during the period for:
Income taxes, net of refunds	$	(15,042	)		$	77,942			$	(14,098	)
Interest, net of amounts capitalized	204,261				196,419				184,210
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	141,297			$	132,620			$	130,057
Dividends declared but not paid	88,000				82,700				77,700
Right-of-use operating lease assets obtained in exchange for operating lease liabilities	11,262				—				—

Intangible Assets

 

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS's software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives.  Amortization expense was $66 million in 2019, $68 million in 2018, and $72 million in 2017.  Estimated amortization expense on existing intangible assets over the next five years is $68 million in 2020, $52 million in 2021, $41 million in 2022, $32 million in 2023, and $22 million in 2024.  At December 31, 2019, the weighted-average remaining amortization period for intangible assets was 8 years.

 

Investments

 

El Dorado holds investments in both debt and equity securities.  Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either

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the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).

Bright Canyon holds investments in equity securities. Investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).

 

Our investments in the nuclear decommissioning trusts, coal reclamation escrow account and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 14 and 20 for more information on these investments.

Business Segments

 

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.

Preferred Stock

At December 31, 2019, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.

Sources of Revenue

The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands):

	Year Ended December 31,				Year Ended December 31,
	2019				2018
Retail Electric Service
Residential	$	1,761,122			$	1,867,370
Non-Residential	1,509,514				1,628,891
Wholesale Energy Sales	121,805				109,198
Transmission Services for Others	62,460				60,261
Other Sources	16,308				25,527
Total Operating Revenues	$	3,471,209			$	3,691,247

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Retail Electric Revenue. Pinnacle West's retail electric revenue is generated by our wholly owned regulated subsidiary APS's sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers' meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed.

Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers' energy requirements. We may also sell generation into the wholesale markets that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by FERC.

    

Revenue Activities

Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the year ended December 31, 2019 and 2018 were $3,415 million and $3,644 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the year ended December 31, 2019 and 2018, our revenues that do not qualify as revenue from contracts with customers were $56 million and $47 million, respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

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Standards Adopted in 2019

ASU 2016-02, Leases

In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard requires a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that is initially measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. Since the issuance of the new lease standard, additional lease related guidance has been issued relating to land easements and how entities may elect to account for these arrangements at transition, among other items. The new lease standard and related amendments were effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings determined at either the date of adoption, or the earliest period presented in the financial statements. The standard includes various optional practical expedients provided to facilitate transition. We adopted this standard, and related amendments, on January 1, 2019. See Note 9 for additional information.

ASU 2018-15, Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract

In August 2018, a new accounting standard was issued that clarifies how customers in a cloud computing service arrangement should account for implementation costs associated with the arrangement. To determine which implementation costs should be capitalized, the new guidance aligns the accounting with existing guidance pertaining to internal-use software. As a result of this new standard, certain cloud computing service arrangement implementation costs will now be subject to capitalization and amortized on a straight-line basis over the cloud computing service arrangement term. The new standard was effective for us on January 1, 2020, with early application permitted, and may have been applied using either a retrospective or prospective transition approach. On July 1, 2019, we early adopted this new accounting standard using the prospective approach. The adoption did not have a material impact on our financial statements.

Standard Adopted in 2020

ASU 2016-13, Financial Instruments: Measurement of Credit Losses

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables, and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses, these changes did not have a material impact on our financial statements.

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2019 Retail Rate Case Filing with the Arizona Corporation Commission

On October 31, 2019, APS filed an application with the ACC for an annual increase in retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction ("SCR") project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” below). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the TEAM. The proposed total revenue increase in APS's application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).

The principal provisions of APS's application are:

•	a test year comprised of twelve months ended June 30, 2019, adjusted as described below;

•	an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•	the following proposed capital structure and costs of capital:

			Capital Structure		Cost of Capital
Long-term debt			45.3	%	4.10	%
Common stock equity			54.7	%	10.15	%
Weighted-average cost of capital					7.41	%

 

•	a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

•	authorization to defer until APS's next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;

•	a number of proposed rate and program changes for residential customers, including:

▪	a super off-peak period during the winter months for APS’s time-of-use with demand rates;

▪	additional $1.25 million in funding for APS's limited-income crisis bill program; and

▪	a flat bill/subscription rate pilot program;

•	proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;

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•	recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see discussion below of the 2017 Settlement Agreement); and

•	continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see "Navajo Plant" below).

APS requested that the increase become effective December 1, 2020.  The hearing for this rate case is currently scheduled to begin in July 2020. APS cannot predict the outcome of its request.

2016 Retail Rate Case Filing with the Arizona Corporation Commission

 

On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54%).

Other key provisions of the agreement include the following:

•	an agreement by APS not to file another general retail rate case application before June 1, 2019;

•	an authorized return on common equity of 10.0%;

•	a capital structure comprised of 44.2% debt and 55.8% common equity;

•	a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;

•	a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing SCR equipment at Four Corners;

•	a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;

•	an expansion of the PSA to include certain environmental chemical costs and third-party energy storage costs;

•	a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation ("DG") with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year in capital costs, and not more than $15 million per year in capital costs;

•	an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;

•	rate design changes, including:

▪	a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;

▪	non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;

▪	a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and

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•	an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.

Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.

On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications.  On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the "2017 Rate Case Decision"), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable.  The complainant requested that the ACC hold a hearing on the amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS) and, if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing.  The ACC held a hearing on this matter beginning in September 2018 and the hearing was concluded on October 1, 2018. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. The ACC considered the matter at its April and May 2019 open meetings, but no decision was issued. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC reconsidered the matter and adopted the Administrative Law Judge's amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.

On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision.  Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year and file a report by May 3, 2019. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision. On April 23, 2019, the ACC Staff indicated that they would need additional time beyond May 3, 2019 to file the requested report.

On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following:

•	APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test-year;

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•	until the conclusion of the rate case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a customer would pay on their most economical rate given their actual usage during each month;

•	APS customers can switch rate plans during an open enrollment period of six months;

•	APS must identify customers whose bills have increased by more than 9% and that are not on the most economical rate and provide such customers with targeted education materials and an opportunity to switch rate plans;

•	APS must provide grandfathered net metering customers on legacy demand rates an opportunity to switch to another legacy rate to enable such customers to fully benefit from legacy net metering rates;

•	APS must fund and implement a supplemental customer education and outreach program to be developed with and administered by ACC Staff and a third-party consultant; and

•	APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage.

APS cannot predict the outcome or impact of the rate case filed on October 31, 2019. APS is assessing the impact to its financial statements of the implementation of the other key provisions of the amended order regarding the rate review and cannot predict at this time whether they will have a material impact on its financial position, results of operations or cash flows. 

Cost Recovery Mechanisms

 

APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms.

 

Renewable Energy Standard.  In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year, APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.

  

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request was lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.

On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital

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carrying costs for this program will be recovered through the RES. On June 12, 2018, the ACC approved the 2018 RES Implementation Plan including a waiver of the distributed energy requirements for the 2018 implementation year.

On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million.  APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. On October 29, 2019, the ACC approved the 2019 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2019 implementation year.

On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2020 contained in the RES rules. The ACC has not yet ruled on the 2020 RES Implementation Plan.

On July 2, 2019, ACC Staff issued draft rules, which propose a RES goal of 45% of retail energy served be renewables by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035.  The draft rules would also require a certain amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives. Nuclear energy would be considered a clean resource under the draft rules. See "Energy Modernization Plan" below for more information.

On January 8, 2020, an ACC commissioner proposed replacing the current RES standard with a new standard ("KREST II"). KREST II sets a RES goal of 50% of retail energy to be served by renewables by 2028, 100% zero carbon resources by 2045, and a 35% energy efficiency resource standard by 2030 with a 10% demand response carve out. APS cannot predict the outcome of this matter.

Demand Side Management Adjustor Charge. The ACC EES requires APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of the ACC. Verified energy savings from APS's resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its LFCR mechanism (see below for discussion of the LFCR).

On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a requested budget of $52.6 million and requests a waiver of the Electric Energy Efficiency Standard for 2018.   On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million. The ACC has not yet ruled on the APS 2018 amended DSM Plan.

On December 31, 2018, APS filed its 2019 DSM Plan, which requests a budget of $34.1 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The ACC has not yet ruled on the APS 2019 DSM Plan.

On December 31, 2019, APS filed its 2020 DSM Plan, which requests a budget of $51.9 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addresses all components of the 2018 and 2019 DSM plans,

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which enables the ACC to review the 2020 DSM Plan only. The ACC has not yet ruled on the APS 2020 DSM Plan.

     

Power Supply Adjustor Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

•	APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

•	An adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

•	The PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

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The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

•	The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2019 and 2018 (dollars in thousands):

	Twelve Months Ended December 31,
	2019				2018
Beginning balance	$	37,164			$	75,637
Deferred fuel and purchased power costs — current period	82,481				78,277
Amounts charged to customers	(49,508		)		(116,750		)
Ending balance	$	70,137			$	37,164

 

The PSA rate for the PSA year beginning February 1, 2018 is $0.004555 per kWh, consisting of a Forward Component of $0.002009 per kWh and a Historical Component of $0.002546 per kWh. This represented a $0.004 per kWh increase over the August 19, 2017 PSA, the maximum permitted under the Plan of Administration for the PSA. This left $16.4 million of 2017 fuel and purchased power costs above this annual cap. These costs rolled over into the following year and were reflected in the 2019 reset of the PSA.

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The PSA rate for the PSA year beginning February 1, 2019 is $0.001658 per kWh, consisting of a Forward Component of $0.000536 per kWh and a Historical Component of $0.001122 per kWh. This represented a $0.002897 per kWh decrease compared to 2018.

On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. That rate was $(0.000456) per kWh and consisted of a Forward Component of $(0.002086) per kWh and a Historical Component of $0.001630 per kWh. The 2020 PSA rate is a $0.002115 per kWh decrease compared to the 2019 PSA year. These rates went into effect as filed on February 1, 2020.

On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA. This application is pending with the ACC. APS cannot predict the outcome of this matter.

    

Environmental Improvement Surcharge ("EIS"). The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations.  A filing is made on or before February 1st for qualified environmental improvements made during the prior calendar year, and the new charge becomes effective April 1 unless suspended by the ACC.  There is an overall cap of $0.0005 per kWh (approximately $13 - 14 million per year).  APS’s February 1, 2020 application requested an increase in the charge to $8.75 million, or $2.0 million over the charge in effect for the 2019-2020 rate effective year.

 Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS's retail customers ("Retail Transmission Charges").  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the settlement agreement entered into in 2012 regarding APS's rate case ("2012 Settlement Agreement"), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

The formula rate is updated each year effective June 1 on the basis of APS's actual cost of service, as disclosed in APS's FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  APS reviews the proposed formula rate filing amounts with the ACC Staff.  Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated at FERC.  Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Act beginning in its 2018 annual transmission formula rate update filing. These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes.

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Effective June 1, 2018, APS's annual wholesale transmission rates for all users of its transmission system decreased by approximately $22.7 million for the twelve-month period beginning June 1, 2018 in accordance with the FERC approved formula.  An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2018.

Effective June 1, 2019, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $4.9 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.

 

Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were first established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh. The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  DG sales losses are determined from the metered output from the DG units.

 

On February 15, 2018, APS filed its 2018 annual LFCR adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million. On February 6, 2019, the ACC approved the 2018 annual LFCR adjustment to become effective March 1, 2019. On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $36.2 million (a $24.5 million decrease from previous levels). On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019. On February 14, 2020, APS filed its 2020 annual LFCR adjustment, requesting that effective May 1, 2020, the annual LFCR recovery amount be reduced to $26.6 million (a $9.6 million decrease from previous levels). APS cannot predict the outcome or timing of the ACC’s consideration of this filing. Because the LFCR mechanism has a balancing account that trues up any under or over recoveries, the delay in implementation does not have an adverse effect on APS.

    

Tax Expense Adjustor Mechanism.  As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. The TEAM expressly applies to APS's retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. On December 22, 2017, the Tax Act was enacted.  This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

On January 8, 2018, APS filed an application with the ACC that addressed the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and reduced rates by $119.1 million annually through an equal cents per kWh credit ("TEAM Phase I").  On February 22, 2018, the ACC approved the reduction of rates through an equal cents per kWh credit. The rate reduction was effective for the first billing cycle in March 2018.

The impact of the TEAM Phase I, over time, is expected to be earnings neutral. However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM Phase I related to the lower federal income tax rate. The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in

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revenues refunded through the TEAM Phase I is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company.

On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers ("TEAM Phase II"). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the final billing cycle of March 2020. Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit are recognized based upon our seasonal kWh sales pattern.

On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 28.5 year period consistent with IRS normalization rules (“TEAM Phase III”).  On October 29, 2019, the ACC approved TEAM Phase III providing both (i) a one-time bill credit of $64 million which was credited to customers on their December 2019 bills, and (ii) a monthly bill credit effective the first billing cycle in December 2019 which will provide an additional benefit of $39.5 million to customers through December 31, 2020. It is currently anticipated that benefits related to the amortization of depreciation related excess deferred taxes for periods beginning after December 31, 2020 will be fully incorporated into the 2019 rate case filing.

Net Metering

In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases.  A hearing was held in April 2016. On October 7, 2016, the Administrative Law Judge issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective with APS’s 2017 Rate Case Decision, the net metering tariff that governs payments for energy exported to the grid from residential rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power until an avoided cost methodology is developed by the ACC.

As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed.  The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.

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In addition, the ACC made the following determinations:

•	Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;

•	Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

•	Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh was included in the 2017 Settlement Agreement and became effective on September 1, 2017.

    

In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018.  This price reflected the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.5 cents per kWh on May 1, 2019.  This price also reflects the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2019.

On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Arizona Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

See "2016 Retail Rate Case Filing with the Arizona Corporation Commission" above for information regarding an ACC order in connection with the rate review of the 2017 Rate Case Decision requiring APS to provide grandfathered net metering customers on legacy demand rates with an opportunity to switch to another legacy rate to enable such customers to benefit from legacy net metering rates.

Subpoena from Arizona Corporation Commissioner Robert Burns

On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.

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On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.

On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC Staff.  As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel.

On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ amended complaint. On March 6, 2018, Commissioner Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted Commissioner Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. Commissioner Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed. Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019. On February 13, 2019, Commissioner Burns filed a notice of appeal. On July 12, 2019, Commissioner Burns filed his opening brief in the Arizona Court of Appeals. APS filed its answering brief on October 21, 2019. The Arizona Court of Appeals granted the request for oral argument but no date has been set. APS and Pinnacle West cannot predict the outcome of this matter.

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Information Requests from Arizona Corporation Commissioners

On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West. In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC. On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018. Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019. APS also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters. The Company's CEO, Mr. Guldner, appeared at the ACC's January 14, 2020 Open Meeting regarding ACC Commissioners' questions about political spending.  Mr. Guldner committed to the ACC that during his tenure, Pinnacle West and APS, and any of their affiliated companies, will not participate in ACC campaign elections through financial contributions or in-kind contributions.

2018 Renewable Energy Ballot Initiative

On February 20, 2018, a renewable energy advocacy organization filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to provide at least 50% of their annual retail sales of electricity from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The initiative was placed on the November 2018 Arizona elections ballot. On November 6, 2018, the initiative failed to receive adequate voter support and was defeated.

Energy Modernization Plan

On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, which consisted of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plan ("IRP") process. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. On April 25, 2019, the ACC Staff issued a set of draft rules in regards to the Energy Modernization Plan and workshops were held on April 29, 2019 regarding these draft rules. On July 2, 2019, the ACC Staff issued a revised set of draft rules, which propose a RES goal of 45% of retail energy served be renewable by 2035 and a goal of 20% of retail sales during peak demand to be from clean energy resources by 2035.  The draft rules also require a certain amount of the RES goal to be derived from distributed renewable storage, for which utilities would be required to offer performance-based incentives.  Nuclear energy would be considered a clean resource under the draft rules. The ACC held various stakeholder meetings and workshops on ACC Staff’s draft energy rules in July through September 2019 and have scheduled a workshop to be held on March 10 - 11, 2020. On February 19, 2020, the ACC Staff issued a revised proposed set of draft rules that will be discussed at the workshop. APS cannot predict the outcome of this matter.

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Integrated Resource Planning

ACC rules require utilities to develop fifteen-year IRPs which describe how the utility plans to serve customer load in the plan timeframe.  The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged.  In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans.  APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows.  Based on an ACC decision, APS was originally required to file its next IRP by April 1, 2020.  On February 20, 2020, the ACC extended the deadline for all utilities to file their IRP’s from April 1, 2020 to June 26, 2020.

Public Utility Regulatory Policies Act

In August 2016, APS filed an application requesting that all of its contracts with qualifying facilities over 100 kW be set at a presumptive maximum 2-year term. A qualifying facility is an eligible energy-producing facility as defined by FERC regulations within a host electric utility’s service territory that has a right to sell to the host utility. Host utilities are required to purchase power from qualifying facilities at an avoided cost as determined by the utility subject to state commission oversight. A hearing was held in August 2019 and briefing on this matter was completed in October 2019 regarding APS’s application. On December 17, 2019, the ACC denied the application and mandated a minimum contract length of 18 years for qualifying facilities over 100 kW and the rate paid to the qualifying facilities will be based on the long-term avoided cost.

Residential Electric Utility Customer Service Disconnections

On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills.  On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period from June 1 through October 15. During the moratorium on disconnections, APS could not charge late fees and interest on amounts that were past due from customers.  Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts.  In accordance with the emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019. The emergency rule changes will be effective for 180 days and may be renewed for one additional 180 day period. During that time, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes.  The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff issued draft amendments to the customer service disconnections rules. Stakeholders submitted initial comments to the draft amendments on September 23, 2019. ACC stakeholder meetings were held in September 2019, October 2019 and January 2020 regarding the customer service disconnections rules. The disconnection moratorium resulted in a negative impact to our 2019 operating results of approximately $10 million pre-tax. APS is further assessing the impact to its financial statements beyond 2019, which will be affected by the results of final rulemaking related to disconnections.

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Retail Electric Competition Rules

On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. An ACC special open meeting workshop was held on December 3, 2018. No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. Interested parties filed comments to the ACC Staff report, and a stakeholder meeting and workshop to discuss the retail electric competition rules was held on July 30, 2019. ACC Commissioners submitted additional questions regarding this matter. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. The ACC has scheduled a workshop for February 25-26, 2020 for further consideration and discussion of the retail electric competition rules. APS cannot predict whether these efforts will result in any changes and, if changes to the rules results, what impact these rules would have on APS.

Rate Plan Comparison Tool

On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and the Company’s meter data management system. APS immediately removed the tool from its website and notified the ACC. The purpose of the tool was to provide customers with a rate plan recommendation that would result in the lowest bills based upon historical usage data. Upon investigation, APS determined that the error may have affected rate plan recommendations to customers between February 4, 2019 and November 14, 2019. APS is providing refunds to approximately 13,000 potentially impacted customers equal to the difference between what they paid for electricity and the amount they would have paid had they selected their most economical rate and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided is not expected to have a material impact on APS's financial statements. The ACC is currently investigating this matter. APS received a civil investigative demand from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section that seeks information pertaining to the rate plan comparison tool offered to APS customers. APS is fully cooperating with the Attorney General’s Office in this matter. APS cannot predict the outcome of these matters.

Four Corners

 

SCE-Related Matters. As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provide transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates.  APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter

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of 2016.  On July 29, 2016, APS filed a request for rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the Transmission Agreement was a jurisdictional contract that should have been filed with FERC. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. On June 14, 2019, the United States Court of Appeals for the Ninth Circuit issued an unpublished memorandum order denying APS’s petition for review of FERC’s orders that denied APS’s request to recover the regulatory asset through its FERC-jurisdictional rates and granting APS’s petition for review of FERC’s orders finding the agreement to be a jurisdictional contract. The United States Court of Appeals for the Ninth Circuit vacated FERC’s determination that the agreement was required to be filed with FERC and remanded the issue to FERC for additional proceedings. On December 18, 2019, APS submitted an offer of settlement to FERC to resolve all outstanding issues related to this matter. The offer of settlement provided that APS would not recover in rates any portion of any payment it made to SCE in connection with the expiration of the Transmission Agreement and FERC would close certain dockets related to this matter. On February 5, 2020, FERC issued an order accepting APS’s offer of settlement and resolved this matter.

SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5.  APS filed the SCR Adjustment request in April 2018.  Consistent with the 2017 Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment.  The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers.  Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019.  The hearing for this matter occurred in September 2018.  At the hearing, APS accepted ACC Staff's recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018.  The ACC has not issued a decision on this matter.  APS included the costs for the SCR project in the retail rate base in its 2019 retail rate case filing with the ACC. APS cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).

Cholla

On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it plans to retire Cholla Unit 4 by the end of 2020.

Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s

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decommissioning and other retirement-related costs ($73 million as of December 31, 2019), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.

On March 20, 2019, APS announced that it began evaluating the feasibility and cost of converting a unit at Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS reported the results of its evaluation on May 9, 2019 to the ACC. On July 10, 2019, the ACC voted to not require APS to file a request for proposal to convert the unit at Cholla to burn biomass.

Navajo Plant

The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant would remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that allows for decommissioning activities to begin after the plant ceased operations in November 2019.

  

APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($82 million as of December 31, 2019) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.

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Regulatory Assets and Liabilities

 

The detail of regulatory assets is as follows (dollars in thousands):

S			December 31, 2019								December 31, 2018
	Amortization Through		Current				Non-Current				Current				Non-Current
Pension	(a)		$	—			$	660,223			$	—			$	733,351
Retired power plant costs	2033		28,182				142,503				28,182				167,164
Income taxes - AFUDC equity	2049		6,800				154,974				6,457				151,467
Deferred fuel and purchased power (b) (c)	2020		70,137				—				37,164				—
Deferred fuel and purchased power — mark-to-market (Note 17)	2024		36,887				33,185				31,728				23,768
Deferred property taxes	2027		8,569				58,196				8,569				66,356
SCR deferral	N/A		—				52,644				—				23,276
Four Corners cost deferral	2024		8,077				32,152				8,077				40,228
Ocotillo deferral	N/A		—				38,144				—				—
Deferred compensation	2036		—				36,464				—				36,523
Income taxes — investment tax credit basis adjustment	2048		1,098				24,981				1,079				25,522
Lost fixed cost recovery (b)	2020		26,067				—				32,435				—
Palo Verde VIEs (Note 19)	2046		—				20,635				—				20,015
Coal reclamation	2026		1,546				17,688				1,546				15,607
Loss on reacquired debt	2038		1,637				12,031				1,637				13,668
Mead-Phoenix transmission line - contributions in aid of construction	2050		332				9,712				332				10,044
TCA balancing account (b)	2021		6,324				2,885				3,860				772
Tax expense of Medicare subsidy	2024		1,235				4,940				1,235				6,176
AG-1 deferral	2022		2,787				2,716				2,654				5,819
Tax expense adjustor mechanism (b)	2020		1,612				—				—				—
Other	Various		1,917				—				1,947				3,185
Total regulatory assets (d)			$	203,207			$	1,304,073			$	166,902			$	1,342,941

(a)	This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.  See Note 8 for further discussion.

(b)	See “Cost Recovery Mechanisms” discussion above.

(c)	Subject to a carrying charge.

(d)	There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”

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The detail of regulatory liabilities is as follows (dollars in thousands):

			December 31, 2019								December 31, 2018
	Amortization Through		Current				Non-Current				Current				Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act (a)	2046		$	59,918			$	1,054,053			$	—			$	1,272,709
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act (a)	2058		6,302				237,357				6,302				243,691
Asset retirement obligations	2057		—				418,423				—				278,585
Removal costs	(c)		47,356				136,072				39,866				177,533
Other postretirement benefits	(d)		37,575				139,634				37,864				125,903
Income taxes - change in rates	2049		2,797				68,265				2,769				70,069
Spent nuclear fuel	2027		6,676				51,019				6,503				57,002
Four Corners coal reclamation	2038		1,059				51,704				1,858				17,871
Income taxes - deferred investment tax credit	2048		2,202				50,034				2,164				51,120
Renewable energy standard (b)	2021		39,287				10,300				44,966				20
Demand side management (b)	2021		15,024				24,146				14,604				4,123
Sundance maintenance	2031		5,698				11,319				1,278				17,228
Property tax deferral	N/A		—				7,046				—				2,611
Tax expense adjustor mechanism (b)	2020		7,018				—				3,237				—
Deferred gains on utility property	2022		2,423				4,163				4,423				6,581
FERC transmission true up	2021		1,045				2,004				—				—
Other	Various		532				2,296				42				930
Total regulatory liabilities			$	234,912			$	2,267,835			$	165,876			$	2,325,976

(a)	For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as "Deferred income taxes" under Cash Flows From Operating Activities.

(b)	See “Cost Recovery Mechanisms” discussion above.

(c)	In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.

(d)	See Note 8.

 

Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes.  The tax effect of these differences is recorded as deferred taxes.  We calculate deferred taxes using currently enacted income tax rates.    

APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Consolidated Balance Sheets in accordance with accounting guidance for regulated operations.  The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy.  The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.

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The Tax Act reduced the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. In accordance with accounting for regulated companies, the effect of this rate reduction was substantially offset by a net regulatory liability.

Federal income tax laws require the amortization of a majority of the balance over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018. On March 13, 2019, the ACC approved the Company's proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve-month period. As a result, the Company began amortization in March 2019. As of December 31, 2019, the Company has recorded $57 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities. On October 29, 2019, the ACC approved the Company’s proposal to amortize depreciation related net excess deferred tax liabilities subject to its jurisdiction over a 28.5-year period with amortization to retroactively begin as of January 1, 2018. As a result, in the fourth quarter of 2019, the Company has recorded $62 million of income tax benefit related to amortization of these depreciation related liabilities. See Note 4 for more details.

    

In August 2018, U.S. Treasury proposed regulations that clarified bonus depreciation transition rules under the Tax Act for regulated public utility property placed in service after September 27, 2017 and before January 1, 2018.  However, these proposed regulations were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. In September 2019, U.S. Treasury issued final regulations, which replaced the August 2018 proposed regulations. These final regulations did not materially impact any tax position taken by the Company for property placed in service after September 27, 2017 and before January 1, 2018.

Along with the September 2019 final regulations, U.S. Treasury also issued new proposed regulations which clarify bonus depreciation transition rules under the Tax Act for property placed in service by regulated public utilities after December 31, 2017. The proposed regulations provide that certain regulated public utility property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020 would continue to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act.  During the third quarter of 2019, as a result of the clarification provided by these proposed regulations, the Company recorded additional deferred tax liabilities of approximately $56 million related to bonus depreciation benefits claimed on the Company’s 2018 tax return.

In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the statement of income.

 

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax.  As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 19 for additional details related to the Palo Verde sale leaseback VIEs.

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The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):

	Pinnacle West Consolidated												APS Consolidated
	2019				2018				2017				2019				2018				2017
Total unrecognized tax benefits, January 1	$	40,731			$	41,966			$	36,075			$	40,731			$	41,966			$	36,075
Additions for tax positions of the current year	3,373				3,436				2,937				3,373				3,436				2,937
Additions for tax positions of prior years	1,843				2,696				4,783				1,843				2,696				4,783
Reductions for tax positions of prior years for:
Changes in judgment	(2,078		)		(1,764		)		(1,829		)		(2,078		)		(1,764		)		(1,829		)
Settlements with taxing authorities	—				—				—				—				—				—
Lapses of applicable statute of limitations	(434		)		(5,603		)		—				(434		)		(5,603		)		—
Total unrecognized tax benefits, December 31	$	43,435			$	40,731			$	41,966			$	43,435			$	40,731			$	41,966

Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):

	Pinnacle West Consolidated												APS Consolidated
	2019				2018				2017				2019				2018				2017
Tax positions, that if recognized, would decrease our effective tax rate	$	22,813			$	19,504			$	16,373			$	22,813			$	19,504			$	16,373

 

As of the balance sheet date, the tax year ended December 31, 2016 and all subsequent tax years remain subject to examination by the IRS.  With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2015.

We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense.  The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):

	Pinnacle West Consolidated												APS Consolidated
	2019				2018				2017				2019				2018				2017
Unrecognized tax benefit interest expense/(benefit) recognized	$	459			$	(780	)		$	577			$	459			$	(780	)		$	577

Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):

 

	Pinnacle West Consolidated												APS Consolidated
	2019				2018				2017				2019				2018				2017
Unrecognized tax benefit interest accrued	$	1,589			$	1,130			$	1,910			$	1,589			$	1,130			$	1,910

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Additionally, as of December 31, 2019, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

The components of income tax expense are as follows (dollars in thousands):

	Pinnacle West Consolidated												APS Consolidated
	Year Ended December 31,												Year Ended December 31,
	2019				2018				2017				2019				2018				2017
Current:
Federal	$	(13,551	)		$	18,375			$	11,624			$	(54,697	)		$	88,180			$	21,512
State	3,195				3,342				3,052				695				1,877				2,778
Total current	(10,356		)		21,717				14,676				(54,002		)		90,057				24,290
Deferred:
Federal	(14,982		)		94,721				223,729				29,321				32,436				221,078
State	9,565				17,464				19,867				15,109				22,321				23,800
Total deferred	(5,417		)		112,185				243,596				44,430				54,757				244,878
Income tax expense/(benefit)	$	(15,773	)		$	133,902			$	258,272			$	(9,572	)		$	144,814			$	269,168

The following chart compares pretax income at the statutory federal income tax rate of 21% in 2019 and 2018 and 35% in 2017 to income tax expense (dollars in thousands):

 

	Pinnacle West Consolidated												APS Consolidated
	Year Ended December 31,												Year Ended December 31,
	2019				2018				2017				2019				2018				2017
Federal income tax expense at statutory rate	$	113,828			$	139,533			$	268,177			$	120,790			$	154,260			$	277,540
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	18,599				23,115				21,380				19,267				24,531				22,329
State income tax credits net of federal income tax benefit	(8,519		)		(6,704		)		(6,483		)		(6,781		)		(5,440		)		(5,053		)
Nondeductible expenditures associated with ballot initiative	—				7,879				—				—				—				—
Stock compensation	(2,252		)		(1,804		)		(6,659		)		(1,054		)		(780		)		(3,489		)
Excess deferred income taxes - Tax Cuts and Jobs Act	(124,082		)		(6,725		)		9,348				(124,082		)		(4,715		)		9,431
Allowance for equity funds used during construction (see Note 1)	(2,476		)		(7,231		)		(12,937		)		(2,476		)		(7,231		)		(12,937		)
Palo Verde VIE noncontrolling interest (see Note 19)	(4,094		)		(4,094		)		(6,823		)		(4,094		)		(4,094		)		(6,823		)
Investment tax credit amortization	(6,851		)		(6,742		)		(6,715		)		(6,851		)		(6,742		)		(6,715		)
Other	74				(3,325		)		(1,016		)		(4,291		)		(4,975		)		(5,115		)
Income tax expense/(benefit)	$	(15,773	)		$	133,902			$	258,272			$	(9,572	)		$	144,814			$	269,168

 

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The components of the net deferred income tax liability were as follows (dollars in thousands):

	Pinnacle West Consolidated								APS Consolidated
	December 31,								December 31,
	2019				2018				2019				2018
DEFERRED TAX ASSETS
Risk management activities	$	17,552			$	15,785			$	17,552			$	15,785
Regulatory liabilities:
Excess deferred income taxes - Tax Cuts and Jobs Act	335,877				376,869				335,877				376,869
Asset retirement obligation and removal costs	143,011				117,201				143,011				117,201
Unamortized investment tax credits	52,236				53,284				52,236				53,284
Other postretirement benefits	43,841				40,532				43,841				40,532
Other	52,382				40,380				52,382				40,380
Pension liabilities	73,210				112,019				67,976				107,009
Coal reclamation liabilities	40,837				47,508				40,837				47,508
Renewable energy incentives	28,066				30,779				28,066				30,779
Credit and loss carryforwards	54,795				1,755				10,992				—
Other	63,102				58,820				70,948				59,919
Total deferred tax assets	904,909				894,932				863,718				889,266
DEFERRED TAX LIABILITIES
Plant-related	(2,448,458		)		(2,277,724		)		(2,448,458		)		(2,277,724		)
Risk management activities	(27		)		(237		)		(27		)		(237		)
Other postretirement assets and other special use funds	(66,399		)		(57,697		)		(65,965		)		(57,274		)
Regulatory assets:
Allowance for equity funds used during construction	(40,023		)		(39,086		)		(40,023		)		(39,086		)
Deferred fuel and purchased power	(35,162		)		(23,086		)		(35,162		)		(23,086		)
Pension benefits	(163,339		)		(181,504		)		(163,339		)		(181,504		)
Retired power plant costs (see Note 4)	(42,228		)		(48,348		)		(42,228		)		(48,348		)
Other	(82,722		)		(72,096		)		(82,722		)		(72,096		)
Other	(18,890		)		(2,575		)		(18,890		)		(2,575		)
Total deferred tax liabilities	(2,897,248		)		(2,702,353		)		(2,896,814		)		(2,701,930		)
Deferred income taxes — net	$	(1,992,339	)		$	(1,807,421	)		$	(2,033,096	)		$	(1,812,664	)

 

As of December 31, 2019, the deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately $62 million, which first begin to expire in 2036, state credit carryforwards net of federal benefit of $23 million, which first begin to expire in 2023, and other federal carryforwards of $9 million. The credit and loss carryforwards amount above has been reduced by $39 million of unrecognized tax benefits.

 

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.

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The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2019 and 2018 (dollars in thousands):

 

	December 31, 2019										December 31, 2018
	Pinnacle West			APS			Total				Pinnacle West			APS			Total
Commitments under Credit Facilities	$	200,000		$	1,000,000		$	1,200,000			$	350,000		$	1,000,000		$	1,350,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(76,675		)	—			(76,675		)		(76,400		)	—			(76,400		)
Amount of Credit Facilities Available	$	123,325		$	1,000,000		$	1,123,325			$	273,600		$	1,000,000		$	1,273,600
Weighted-Average Commitment Fees	0.125%			0.100%							0.125%			0.100%

Pinnacle West

 

On May 9, 2019, Pinnacle West entered into a $50 million term loan agreement that matures May 7, 2020. Pinnacle West used the proceeds to refinance indebtedness under and terminate a prior $150 million revolving credit facility. Borrowings under the agreement bear interest at London Inter-bank Offered Rate ("LIBOR") plus 0.55% per annum. At December 31, 2019, Pinnacle West had $38 million in outstanding borrowings under the agreement.

At December 31, 2019, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West's senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At December 31, 2019, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $77 million of commercial paper borrowings.

APS

 

At December 31, 2019, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At December 31, 2019, APS had no commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 11 for a discussion of APS's other outstanding letters of credit.

Debt Provisions

 

On November 27, 2018, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power). See Note 7 for additional long-term debt provisions.

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All of Pinnacle West’s and APS’s debt is unsecured.  The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2019 and 2018 (dollars in thousands):

	Maturity		Interest		December 31,
	Dates (a)		Rates		2019				2018
APS
Pollution control bonds:
Variable	2029		(b)		$	35,975			$	35,975
Fixed	2024		4.70%		115,150				115,150
Total pollution control bonds					151,125				151,125
Senior unsecured notes	2020-2049		2.20%-6.88%		4,875,000				4,575,000
Term loans			(c)		200,000				—
Unamortized discount					(12,434		)		(12,638		)
Unamortized premium					7,423				7,736
Unamortized debt issuance cost					(37,981		)		(31,787		)
Total APS long-term debt					5,183,133				4,689,436
Less current maturities					350,000				500,000
Total APS long-term debt less current maturities					4,833,133				4,189,436
Pinnacle West
Senior unsecured notes	2020		2.25%		300,000				300,000
Term loan	2020		(d)		150,000				150,000
Unamortized discount					(57		)		(121		)
Unamortized debt issuance cost					(518		)		(1,083		)
Total Pinnacle West long-term debt					449,425				448,796
Less current maturities					450,000				—
Total Pinnacle West long-term debt less current maturities					(575		)		448,796
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES					$	4,832,558			$	4,638,232

(a)	This schedule does not reflect the timing of redemptions that may occur prior to maturities.

(b)	The weighted-average rate for the variable rate pollution control bonds was 1.54% at December 31, 2019 and 1.76% at December 31, 2018.

(c)	The weighted-average interest rate was 2.12% at December 31, 2019.

(d)	The weighted-average interest rate was 2.20% at December 31, 2019 and 3.02% at December 31, 2018.

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The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):

Year		Consolidated Pinnacle West				Consolidated APS
2020		$	800,000			$	350,000
2021		—				—
2022		—				—
2023		—				—
2024		365,150				365,150
Thereafter		4,510,975				4,510,975
Total		$	5,676,125			$	5,226,125

 

Debt Fair Value

 

Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 

	As of December 31, 2019								As of December 31, 2018
	Carrying Amount				Fair Value				Carrying Amount				Fair Value
Pinnacle West	$	449,425			$	450,822			$	448,796			$	443,955
APS	5,183,133				5,743,570				4,689,436				4,789,608
Total	$	5,632,558			$	6,194,392			$	5,138,232			$	5,233,563

 

Credit Facilities and Debt Issuances

 

APS

 

On February 26, 2019, APS entered into a $200 million term loan agreement that matures August 26, 2020. APS used the proceeds to repay existing indebtedness. Borrowings under the agreement bear interest at LIBOR plus 0.50% per annum.

On February 28, 2019, APS issued $300 million of 4.25% unsecured senior notes that mature on March 1, 2049. The net proceeds from the sale, together with funds made available from the term loan described above, were used to repay existing indebtedness.

On March 1, 2019, APS repaid at maturity $500 million aggregate principal amount of its 8.75% senior notes.

On August 19, 2019, APS issued $300 million of 2.6% unsecured senior notes that mature on August 15, 2029. The net proceeds from the sale were used to repay short-term indebtedness, consisting of commercial paper borrowings, and to replenish cash used to fund capital expenditures.

On November 20, 2019, APS issued $300 million of 3.5% unsecured senior notes that mature on December 1, 2049. The net proceeds from the sale were used to repay short-term indebtedness, consisting of commercial paper borrowings, to replenish cash used to fund capital expenditures, and to redeem, on December 30, 2019, $100 million of the $250 million aggregate principal amount of our 2.2% Notes due January 15, 2020.

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On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% senior notes mentioned above.

See “Lines of Credit and Short-Term Borrowings” in Note 6 and “Financial Assurances” in Note 11 for discussion of APS’s separate outstanding letters of credit.

 

Debt Provisions

 

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant.  For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%.  At December 31, 2019, the ratio was approximately 52% for Pinnacle West and 47% for APS.  Failure to comply with such covenant levels would result in an event of default, which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt.  See further discussion of “cross-default” provisions below.

 

Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade.  However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.

 

All of Pinnacle West’s loan agreements contain "cross-default" provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements.  All of APS’s bank agreements contain "cross-default" provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements.  Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On November 27, 2018, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved an increase in APS’s long-term debt authorization from $5.1 billion to $5.9 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs.  See Note 6 for additional short-term debt provisions.

 

Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries.  All new employees participate in the account balance plan.  Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant.  The pension plan covers nearly all employees.  The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors.  Our employees do not contribute to the plans.  We calculate the benefits based on age, years of service and pay.

Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement) for the employees of Pinnacle West and its subsidiaries.  These plans provide medical and life

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insurance benefits to retired employees.  Employees must retire to become eligible for these retirement benefits, which are based on years of service and age.  For the medical insurance plan, retirees make contributions to cover a portion of the plan costs.  For the life insurance plan, retirees do not make contributions.  We retain the right to change or eliminate these benefits.

Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement date.  See Note 14 for further discussion of how fair values are determined.  Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

 

A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates.  Accordingly, these changes are recorded as a regulatory asset or regulatory liability.

 

The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):

	Pension												Other Benefits
	2019				2018				2017				2019				2018				2017
Service cost-benefits earned during the period	$	49,902			$	56,669			$	54,858			$	18,369			$	21,100			$	17,119
Interest cost on benefit obligation	136,843				124,689				129,756				29,894				28,147				29,959
Expected return on plan assets	(171,884		)		(182,853		)		(174,271		)		(38,412		)		(42,082		)		(53,401		)
Amortization of:
Prior service cost (credit)	—				—				81				(37,821		)		(37,842		)		(37,842		)
Net actuarial loss	42,584				32,082				47,900				—				—				5,118
Net periodic benefit cost (benefit)	$	57,445			$	30,587			$	58,324			$	(27,970	)		$	(30,677	)		$	(39,047	)
Portion of cost charged to expense	$	30,312			$	10,120			$	27,295			$	(19,859	)		$	(21,426	)		$	(18,274	)

 

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The following table shows the plans’ changes in the benefit obligations and funded status for the years 2019 and 2018 (dollars in thousands):

	Pension								Other Benefits
	2019				2018				2019				2018
Change in Benefit Obligation
Benefit obligation at January 1	$	3,190,626			$	3,394,186			$	676,771			$	753,393
Service cost	49,902				56,669				18,369				21,100
Interest cost	136,843				124,689				29,894				28,147
Benefit payments	(177,882		)		(184,161		)		(32,486		)		(31,540		)
Actuarial (gain) loss	413,625				(200,757		)		54,376				(94,329		)
Benefit obligation at December 31	3,613,114				3,190,626				746,924				676,771
Change in Plan Assets
Fair value of plan assets at January 1	2,733,476				3,057,027				723,677				1,022,371
Actual return on plan assets	602,030				(201,078		)		144,095				(40,354		)
Employer contributions	150,000				50,000				—				—
Benefit payments	(167,155		)		(172,473		)		(30,278		)		(72,453		)
Transfer to active union medical account	—				—				—				(185,887		)
Fair value of plan assets at December 31	3,318,351				2,733,476				837,494				723,677
Funded Status at December 31	$	(294,763	)		$	(457,150	)		$	90,570			$	46,906

The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2019 and 2018 (dollars in thousands):

	2019				2018
Projected benefit obligation	$	177,775			$	3,190,626
Accumulated benefit obligation	169,091				3,038,774
Fair value of plan assets	—				2,733,476

 

The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on an accumulated benefits obligation basis at December 31, 2019, therefore the only pension plan with an accumulated benefits obligation in excess of plan assets in 2019 is a non-qualified supplemental excess benefit retirement plan.

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2019 and 2018 (dollars in thousands):

	Pension								Other Benefits
	2019				2018				2019				2018
Noncurrent asset	$	—			$	—			$	90,570			$	46,906
Current liability	(14,578		)		(13,980		)		—				—
Noncurrent liability	(280,185		)		(443,170		)		—				—
Net amount recognized	$	(294,763	)		$	(457,150	)		$	90,570			$	46,906

 

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The following table shows the details related to accumulated other comprehensive loss as of December 31, 2019 and 2018 (dollars in thousands): 

	Pension								Other Benefits
	2019				2018				2019				2018
Net actuarial loss	$	735,186			$	794,292			$	12,238			$	63,544
Prior service credit	—				—				(189,912		)		(227,733		)
APS’s portion recorded as a regulatory (asset) liability	(660,223		)		(733,351		)		177,209				163,767
Income tax expense (benefit)	(18,546		)		(15,083		)		570				561
Accumulated other comprehensive loss	$	56,417			$	45,858			$	105			$	139

 

The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets and liabilities into net periodic benefit cost in 2020 (dollars in thousands):

	Pension				Other Benefits
Net actuarial loss	$	33,642			$	—
Prior service credit	—				(37,575		)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2020	$	33,642			$	(37,575	)

The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:

	Benefit Obligations As of December 31,						Benefit Costs For the Years Ended December 31,
	2019			2018			2019			2018			2017
Discount rate – pension	3.30	%		4.34	%		4.34	%		3.65	%		4.08	%
Discount rate – other benefits	3.42	%		4.39	%		4.39	%		3.71	%		4.17	%
Rate of compensation increase	4.00	%		4.00	%		4.00	%		4.00	%		4.00	%
Expected long-term return on plan assets - pension	N/A			N/A			6.25	%		6.05	%		6.55	%
Expected long-term return on plan assets - other benefits	N/A			N/A			5.40	%		5.40	%		6.05	%
Initial healthcare cost trend rate (pre-65 participants)	7.00	%		7.00	%		7.00	%		7.00	%		7.00	%
Initial healthcare cost trend rate (post-65 participants)	4.75	%		4.75	%		4.75	%		4.75	%		5.00	%
Ultimate healthcare cost trend rate	4.75	%		4.75	%		4.75	%		4.75	%		5.00	%
Number of years to ultimate trend rate (pre-65 participants)	6			7			7			8			4

 

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan.  For 2020, we are assuming a 5.75% long-term rate of return for pension assets and 5.00% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

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In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs.  A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects on our December 31, 2019 amounts (dollars in thousands): 

	1% Increase				1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	9,299			$	(3,827	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	9,434				(7,257		)
Effect on the accumulated other postretirement benefit obligation	124,073				(97,710		)

 

Plan Assets

 

The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”).  The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities.

 

The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations.  To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets.  The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status.  The plan’s funded status is reviewed on at least a monthly basis.

 

Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended to offset changes in the benefit obligations due to changes in interest rates.  Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury and other government agencies, U.S. Treasury Futures Contracts, and fixed income debt securities issued by corporations.  Long-term fixed income assets may also include interest rate swaps, and other instruments.

 

Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility.  Return-generating assets are composed of U.S. equities, international equities, and alternative investments.  International equities include investments in both developed and emerging markets.  Alternative investments include investments in real estate, private equity and various other strategies.  The plan may also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts and mutual funds.

Based on the IPS, and given the pension plan's funded status at year-end 2019, the target and actual allocation for the pension plan at December 31, 2019 are as follows:

	Pension
	Target Allocation			Actual Allocation
Long-term fixed income assets	62	%		63	%
Return-generating assets	38	%		37	%
Total	100	%		100	%

The permissible range is within +/- 3% of the target allocation shown in the above table, and also considers the plan's funded status.

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The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:

Asset Class	Target Allocation
Equities in US and other developed markets	18	%
Equities in emerging markets	6	%
Alternative investments	14	%
Total	38	%

The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade. 

As of December 31, 2019, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability.  Some of these asset allocation target mixes vary with the plan’s funded status. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2019:

	Other Benefits
	Actual Allocation
Long-term fixed income assets	68	%
Return-generating assets	32	%
Total	100	%

 

See Note 14 for a discussion on the fair value hierarchy and how fair value methodologies are applied.  The plans invest directly in fixed income, U.S. Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts.  Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1.  U.S. Treasury Futures Contracts are valued using the quoted active market prices from the exchange on which they trade, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality.  These instruments are classified as Level 2.

 

Mutual funds, partnerships, and common and collective trusts are valued utilizing a Net Asset Value (NAV) concept or its equivalent. Mutual funds, which includes exchange traded funds (ETFs), are classified as Level 1 and valued using a NAV that is observable and based on the active market in which the fund trades.

Common and collective trusts are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index).  The trust's shares are offered to a limited group of investors, and are not traded in an active market. Investments in common and collective trusts are valued using NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities, and fixed income securities is derived from the market prices of the underlying securities held by the trusts. The

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NAV for trusts investing in real estate is derived from the appraised values of the trust's underlying real estate assets.  As of December 31, 2019, the plans were able to transact in the common and collective trusts at NAV.

Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships' underlying assets. The plan's partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies. Certain partnerships also include funding commitments that may require the plan to contribute up to $50 million to these partnerships; as of December 31, 2019, approximately $38 million of these commitments have been funded.

 

The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value.  We have internal control procedures to ensure this information is consistent with fair value accounting guidance.  These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.

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The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2019, by asset category, are as follows (dollars in thousands):

 

	Level 1				Level 2				Other (a)				Total
Pension Plan:
Cash and cash equivalents	$	9,370			$	—			$	—			$	9,370
Fixed income securities:
Corporate	—				1,541,729				—				1,541,729
U.S. Treasury	406,112				—				—				406,112
Other (b)	—				92,240				—				92,240
Common stock equities (c)	250,829				—				—				250,829
Mutual funds (d)	185,928				—				—				185,928
Common and collective trusts:
Equities	—				—				392,403				392,403
Real estate	—				—				171,645				171,645
Fixed Income	—				—				98,065				98,065
Partnerships	—				—				103,796				103,796
Short-term investments and other (e)	—				—				66,234				66,234
Total	$	852,239			$	1,633,969			$	832,143			$	3,318,351
Other Benefits:
Cash and cash equivalents	$	2,184			$	—			$	—			$	2,184
Fixed income securities:
Corporate	—				202,640				—				202,640
U.S. Treasury	353,650				—				—				353,650
Other (b)	—				7,999				—				7,999
Common stock equities (c)	146,316				—				—				146,316
Mutual funds (d)	14,351				—				—				14,351
Common and collective trusts:
Equities	—				—				83,648				83,648
Real estate	—				—				19,806				19,806
Short-term investments and other (e)	2,881				—				4,019				6,900
Total	$	519,382			$	210,639			$	107,473			$	837,494

(a)	These investments primarily represent assets valued using NAV as a practical expedient, and have not been classified in the fair value hierarchy.

(b)	This category consists primarily of debt securities issued by municipalities.

(c)	This category primarily consists of U.S. common stock equities.

(d)	These funds invest in international common stock equities.

(e)	This category includes plan receivables and payables.

 

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The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2018, by asset category, are as follows (dollars in thousands):

	Level 1				Level 2				Other (a)				Total
Pension Plan:
Cash and cash equivalents	$	451			$	—			$	—			$	451
Fixed income securities:
Corporate	—				1,237,744				—				1,237,744
U.S. Treasury	372,649				—				—				372,649
Other (b)	—				78,902				—				78,902
Common stock equities (c)	196,661				—				—				196,661
Mutual funds (d)	120,976				—				—				120,976
Common and collective trusts:
Equities	—				—				272,926				272,926
Real estate	—				—				165,123				165,123
Fixed Income	—				—				86,483				86,483
Partnerships	—				—				125,217				125,217
Short-term investments and other (e)	—				—				76,344				76,344
Total	$	690,737			$	1,316,646			$	726,093			$	2,733,476
Other Benefits:
Cash and cash equivalents	$	93			$	—			$	—			$	93
Fixed income securities:
Corporate	—				163,286				—				163,286
U.S. Treasury	318,017				—				—				318,017
Other (b)	—				7,531				—				7,531
Common stock equities (c)	129,199				—				—				129,199
Mutual funds (d)	10,963				—				—				10,963
Common and collective trusts:
Equities	—				—				65,720				65,720
Real estate	—				—				19,054				19,054
Short-term investments and other (e)	3,633				—				6,181				9,814
Total	$	461,905			$	170,817			$	90,955			$	723,677

(a)	These investments primarily represent assets valued using NAV as a practical expedient, and have not been classified in the fair value hierarchy.

(b)	This category consists primarily of debt securities issued by municipalities.

(c)	This category primarily consists of U.S. common stock equities.

(d)	These funds invest in U.S. and international common stock equities.

(e)	This category includes plan receivables and payables.

Contributions

 

Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions.  We made contributions to our pension plan totaling $150 million in 2019, $50 million in 2018, and $100 million in 2017.  The minimum required contributions for the pension plan are zero for the next three years.  We expect to make voluntary contributions up to $100 million per year during the 2020-2022 period.  With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2019 and 2018. We made a contribution of approximately $1 million in 2017.  We do not expect to make any contributions over the next three years to our other postretirement benefit plans. The Company was

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reimbursed $30 million in 2019 and $72 million in 2018 for prior years retiree medical claims from the other postretirement benefit plan trust assets. The Company was not reimbursed in 2017.

 

Estimated Future Benefit Payments

 

Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands):

Year		Pension				Other Benefits
2020		$	199,395			$	31,531
2021		201,597				32,777
2022		206,618				33,566
2023		213,208				34,415
2024		218,150				34,468
Years 2025-2029		1,111,171				174,607

 

Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.

Employee Savings Plan Benefits

 

Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries.  In 2019, costs related to APS’s employees represented 99% of the total cost of this plan.  In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments.  Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions.  Pinnacle West recorded expenses for this plan of approximately $11 million for 2019, $11 million for 2018, and $10 million for 2017.

 

We lease certain land, buildings, vehicles, equipment and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2020 through 2050. Substantially all of our leasing activities relate to APS.

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary.  As the primary beneficiary, APS consolidated these lessor trust entities.  The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation.  See Note 19 for a discussion of VIEs.

On January 1, 2019 we adopted new lease accounting guidance (see Note 3). We elected the transition method that allows us to apply the new lease guidance on the date of adoption, January 1, 2019, and will not retrospectively adjust prior periods. We also elected certain transition practical expedients that allow us to not reassess (a) whether any expired or existing contracts are or contain leases, (b) the lease classification for any expired or existing leases and (c) initial direct costs for any existing leases. These practical expedients apply to leases that commenced prior to January 1, 2019. Furthermore, we elected the practical expedient transition provisions relating to the treatment of existing land easements.

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On January 1, 2019 the adoption of this new accounting standard resulted in the recognition on our Consolidated Balance Sheets of approximately $194 million of right-of-use lease assets and $119 million of lease liabilities relating to our operating lease arrangements. The right-of-use lease assets include $85 million of prepaid lease costs that have been reclassified from other deferred debits, and $10 million of deferred lease costs that have been reclassified from other current liabilities. In addition to these balance sheet impacts, the adoption of the guidance resulted in expanded lease disclosures, which are included below.

The following table provides information related to our lease costs (dollars in thousands):

		Year Ended December 31, 2019
		Purchased Power Lease Contracts				Land, Property & Equipment Leases				Total
Operating lease cost		$	42,190			$	18,038			$	60,228
Variable lease cost		113,233				782				114,015
Short-term lease cost		—				4,385				4,385
Total lease cost		$	155,423			$	23,205			$	178,628

Lease costs are primarily included as a component of operating expenses on our Consolidated Statements of Income. Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements have lease terms with non-consecutive periods of use. For these agreements we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet.

Lease disclosures relating to 2018 and 2017 are presented under prior lease accounting guidance. Lease expense recognized in the Consolidated Statements of Income was $18 million in 2018 and $18 million in 2017, these amounts do not include purchased power lease contracts. Operating lease cost for purchased power lease contracts was $47 million in 2018 and $60 million in 2017. In addition, contingent rents for purchased power lease contracts was $109 million in 2018 and $100 million in 2017. These purchased power lease costs are recorded in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4).

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The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):

		December 31, 2019
Year		Purchased Power Lease Contracts (a)				Land, Property & Equipment Leases				Total
2020		$	—			$	14,698			$	14,698
2021		—				11,963				11,963
2022		—				8,331				8,331
2023		—				6,326				6,326
2024		—				4,141				4,141
Thereafter		—				38,697				38,697
Total lease commitments		—				84,156				84,156
Less imputed interest		—				19,571				19,571
Total lease liabilities		$	—			$	64,585			$	64,585

    

(a) As of December 31, 2019, we had no operating lease liabilities relating to purchased power lease contracts. See discussion below regarding executed contracts with commencement dates beginning in June 2020.

We recognize lease assets and liabilities upon lease commencement. At December 31, 2019, we have additional lease arrangements that have been executed, but have not yet commenced. These arrangements primarily relate to purchased power lease contracts. These leases have commencement dates beginning in June 2020 with terms ending through October 2027. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $705 million over the term of the arrangements.

The following table provides information related to estimated future minimum operating lease payments (dollars in thousands):

		December 31, 2018
Year		Purchased Power Lease Contracts				Land, Property & Equipment Leases				Total
2019		$	54,499			$	13,747			$	68,246
2020		—				12,428				12,428
2021		—				9,478				9,478
2022		—				6,513				6,513
2023		—				5,359				5,359
Thereafter		—				42,236				42,236
Total future lease commitments		$	54,499			$	89,761			$	144,260

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The following tables provide other additional information related to operating lease liabilities:

	December 31, 2019
Weighted average remaining lease term	13 years
Weighted average discount rate (a)	3.71	%

(a) Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities.  We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.

	Year Ended December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities - operating cash flows (dollars in thousands):	$	69,075

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APS shares ownership of some of its generating and transmission facilities with other companies.  We are responsible for our share of operating costs which are included in the corresponding operating expenses on our Consolidated Statements of Income. We are also responsible for providing our own financing.  Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation.  The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2019 (dollars in thousands):

		Percent Owned					Plant in Service				Accumulated Depreciation				Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3		29.1	%				$	1,877,748			$	1,102,609			$	22,071
Palo Verde Unit 2 (a)		16.8	%				634,545				377,722				11,831
Palo Verde Common		28.0	%		(b)		746,653				290,084				46,570
Palo Verde Sale Leaseback					(a)		351,050				249,144				—
Four Corners Generating Station		63.0	%				1,520,171				559,272				44,842
Cholla common facilities (c)		50.5	%				184,608				95,720				1,323
Transmission facilities:
ANPP 500kV System		33.5	%		(b)		133,396				51,248				2,723
Navajo Southern System		26.7	%		(b)		89,672				31,985				194
Palo Verde — Yuma 500kV System		19.0	%		(b)		15,274				6,486				4,886
Four Corners Switchyards		63.0	%		(b)		69,994				16,674				2,395
Phoenix — Mead System		17.1	%		(b)		39,355				18,570				53
Palo Verde — Rudd 500kV System		50.0	%				93,112				26,719				317
Morgan — Pinnacle Peak System		64.6	%		(b)		117,752				18,822				—
Round Valley System		50.0	%				515				164				—
Palo Verde — Morgan System		88.9	%		(b)		238,689				13,146				—
Hassayampa — North Gila System		80.0	%				143,422				12,676				—
Cholla 500kV Switchyard		85.7	%				7,651				1,597				535
Saguaro 500kV Switchyard		60.0	%				20,425				12,949				—
Kyrene — Knox System		50.0	%				578				315				—

(a)	See Note 19.

(b)	Weighted-average of interests.

(c)	PacifiCorp owns Cholla Unit 4 (see Note 4 for additional information) and APS operates the unit for PacifiCorp.  The common facilities at Cholla are jointly-owned.

See "Navajo Plant" in Note 4 for more details.

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Palo Verde Generating Station

 

Spent Nuclear Fuel and Waste Disposal

 

On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE in the United States Court of Federal Claims ("Court of Federal Claims").  The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act.  On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

APS has submitted five claims pursuant to the terms of the August 18, 2014 settlement agreement, for five separate time periods during July 1, 2011 through June 30, 2018. The DOE has approved and paid $84.3 million for these claims (APS’s share is $24.5 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 4). On October 31, 2019, APS filed its next claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $16 million (APS’s share is $4.7 million). On February 11, 2020, the DOE approved a payment of $15.4 million (APS’s share is $4.5 million).

Nuclear Insurance

 

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan.  In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately $13.9 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI").  The remaining balance of approximately $13.5 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program.  If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums.  The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident.  Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million.

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion.  APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL").  APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL

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policies totals approximately $25.5 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses.  In addition, NEIL policies contain rating triggers that would result in APS providing approximately $73.4 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade.  The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

 

Fuel and Purchased Power Commitments and Purchase Obligations

 

APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2020 and 2043 that include required purchase provisions.  APS estimates the contract requirements to be approximately $590 million in 2020; $613 million in 2021; $624 million in 2022; $616 million in 2023; $581 million in 2024; and $5.5 billion thereafter.  However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. These amounts include estimated commitments relating to purchased power lease contracts (see Note 9).

 

Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions.  The current coal contracts with take-or-pay provisions have terms expiring through 2031.

 

The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):

 

	Years Ended December 31,
	2020				2021				2022				2023				2024				Thereafter
Coal take-or-pay commitments (a)	$	185,347			$	186,554			$	187,400			$	189,120			$	193,192			$	1,240,964

 

(a)	Total take-or-pay commitments are approximately $2.2 billion.  The total net present value of these commitments is approximately $1.6 billion.

 

APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):

 

	Year Ended December 31,
	2019				2018				2017
Total purchases	$	204,888			$	206,093			$	165,220

 

Renewable Energy Credits

 

APS has entered into contracts to purchase renewable energy credits to comply with the RES.  APS estimates the contract requirements to be approximately $36 million in 2020; $35 million in 2021; $31 million in 2022; $30 million in 2023; $28 million in 2024; and $133 million thereafter.  These amounts do not include purchases of renewable energy credits that are bundled with energy.

 

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Coal Mine Reclamation Obligations

 

APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation.  We account for contemporaneous reclamation costs as part of the cost of the delivered coal.  We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation.  These studies utilize various assumptions to estimate the future costs.  Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $166 million at December 31, 2019 and $213 million at December 31, 2018. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows:  $17 million in 2020; $16 million in 2021; $17 million in 2022; $18 million in 2023; $19 million in 2024; and $88 million thereafter.  Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements.

Superfund-Related Matters

 

The Comprehensive Environmental Response Compensation and Liability Act ("CERCLA" or "Superfund") establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air.  Those who released, generated, transported to, or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible ("PRPs").  PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona.  APS has facilities that are within this Superfund site.  APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3.  In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("RI/FS").  Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS in the spring or summer of 2020. We estimate that our costs related to this investigation and study will be approximately $2 million.  We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

 

On August 6, 2013, Roosevelt Irrigation District ("RID") filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants.  The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID.  The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3.  As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area.  APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation, but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS's exposure or risk related to these matters.

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On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID's CERCLA claims concerning both past and future cost recovery. APS's share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. On August 16, 2019, Maricopa County, one of the three direct defendants in the service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

 

Environmental Matters

 

APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs.  These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs.  Associated capital expenditures or operating costs could be material.  APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery.  The following proposed and final rules involve material compliance costs to APS.

 

Regional Haze Rules.  APS has received the final rulemaking imposing new pollution control requirements on Four Corners. EPA required the plant to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plant. In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval.

Four Corners. Based on EPA’s final standards, APS's 63% share of the cost of required controls for Four Corners Units 4 and 5 was approximately $400 million, which has been incurred.  In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso's 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC purchased the interest from 4CA on July 3, 2018. See "Four Corners - 4CA Matter" below for a discussion of the NTEC purchase. The cost of the pollution controls related to the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest.

Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program.  In September 2014, APS met with EPA to propose a compromise BART strategy, whereby APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See "Cholla" in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset.) APS made the proposal with the understanding that additional emission control equipment is unlikely to be required in the future because retiring and/or converting the units as contemplated in the proposal is more cost effective than, and will result in increased visibility improvement over, the BART requirements for oxides of nitrogen ("NOx") imposed through EPA's BART FIP. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017.

 

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Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act ("RCRA") and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment that is contaminating groundwater above a regulated constituent’s groundwater protection standard to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed "forced closure" or "closure for cause" of unlined surface impoundments, and are the subject of recent regulatory and judicial activities described below.

Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:

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Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to, either, authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits.

•

On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019 to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.

•

Based on an August 21, 2018 D.C. Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations. On November 4, 2019, EPA proposed that all unlined CCR surface impoundments, regardless of their impact (or lack thereof) upon surrounding groundwater, must cease operation and initiate closure by August 31, 2020 (with an optional three-month extension as needed for the completion of alternative disposal capacity).

•

On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure. Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations. EPA’s proposal regarding alternative closure would require express EPA authorization for such facilities to continue operating their CCR disposal units under alternative closure.

We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action. Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect APS’s financial position, results of operations, or cash flows.

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APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $15 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS's share of incremental costs is approximately $1 million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring.

As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must cease operating and initiate closure by October 31, 2020. APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to late-2020. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action. In addition, APS will solicit input from the public, host public hearings, and select remedies as part of this process. Based on the work performed to date, APS currently estimates that its share of corrective action and monitoring costs at Four Corners will likely range from $10 million to $15 million, which would be incurred over 30 years. The analysis needed to perform a similar cost estimate for Cholla remains ongoing at this time. As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change. Given uncertainties that may exist until we have fully completed the corrective action assessment process, we cannot predict any ultimate impacts to the Company; however, at this time we do not believe the cost estimates for Cholla and any potential change to the cost estimate for Four Corners would have a material impact on our financial position, results of operations or cash flows.

Clean Power Plan/Affordable Clean Energy Regulations. On June 19, 2019, EPA took final action on its proposals to repeal EPA's 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and those regulations had been stayed pending judicial review.

The ACE regulations are based upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the CPP, EPA's ACE regulations would not involve utility-level generation dispatch shifting away from coal-fired generation and toward renewable energy resources and natural gas-fired combined cycle power plants. EPA’s ACE regulations provide states and EPA regions such as the Navajo Nation with three years to develop plans establishing source-specific standards of performance based upon application of the ACE rule’s heat-rate improvement emission guidelines. While corresponding New Source Review (“NSR”) reform regulations were proposed as part of EPA’s initial ACE proposal, the finalized ACE regulations did not include such reform measures. EPA announced that it will be taking final action on EPA's NSR reform proposal for EGUs in the near future.

We cannot at this time predict the outcome of EPA's regulatory actions repealing and replacing the CPP. Various state governments, industry organizations, and environmental and public-health public interest groups have filed lawsuits in the D.C. Circuit challenging the legality of EPA’s action, both in repealing the CPP and issuing the ACE regulations. In addition, to the extent that the ACE regulations go into effect as finalized, it is not yet clear how the state of Arizona or EPA will implement these regulations as applied to APS’s coal-fired EGUs. In light of these uncertainties, APS is still evaluating the impact of the ACE regulations on its coal-fired generation fleet.

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Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants.  The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants.  The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments.  APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.

 

Federal Agency Environmental Lawsuit Related to Four Corners

On April 20, 2016, several environmental groups filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement ("OSM") and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine.  The lawsuit alleges that these federal agencies violated both the Endangered Species Act ("ESA") and the National Environmental Policy Act ("NEPA") in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016.  APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016.

On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. On July 29, 2019, the Ninth Circuit Court of Appeals affirmed the September 2017 dismissal of the lawsuit, after which the environmental group plaintiffs petitioned the Ninth Circuit for rehearing on September 12, 2019. The Ninth Circuit denied this petition for rehearing on December 11, 2019.

Four Corners National Pollutant Discharge Elimination System ("NPDES") Permit

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ("EAB") concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018.  The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities.  To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis. The EAB thereafter dismissed the environmental group appeal on February 12, 2019. EPA then issued a revised final NPDES permit for Four Corners on September 30, 2019. This permit is now subject to a petition for review before the EPA Environmental Appeals Board, based upon a November 1, 2019 filing by several environmental groups. We cannot predict the outcome of this review and whether the review will have a material impact on our financial position, results of operations or cash flows.

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Four Corners

4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest and ultimately purchased the interest on July 3, 2018. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC's 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West's guarantee is secured by a portion of APS's payments to be owed to NTEC under the 2016 Coal Supply Agreement.

The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest. These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. The amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) is approximately $10 million, which was due to 4CA on December 31, 2019. Such payment was satisfied in January 2020 by NTEC directing to 4CA a prepayment from APS of future coal payment obligations.

Financial Assurances

 

In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. As of December 31, 2019, standby letters of credit totaled $1.7 million and will expire in 2020. As of December 31, 2019, surety bonds expiring through 2020 totaled $14 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

 

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements.  Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.  Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

 

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2019. In connection with the sale of 4CA's 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. (See "Four Corners - 4CA Matter" above for information related to this guarantee.) A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee to be immaterial.

In connection with BCE’s acquisition of minority ownership positions in the Clear Creek and Nobles 2 wind farms, Pinnacle West has issued parental guarantees to guarantee the obligations of BCE subsidiaries to make required equity contributions to fund project construction (the “Equity Contribution Guarantees”) and to

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In 2019, APS received updated decommissioning estimates for the Navajo Plant closure in December 2019, which resulted in a decrease to the ARO in the amount of $8 million (see Note 4 for additional information). In addition, APS received a new decommissioning study for Palo Verde. This resulted in a decrease to the ARO in the amount of $89 million, a decrease in plant in service of $80 million and a reduction in the regulatory liability of $9 million.

In 2018, APS recognized an ARO for the removal of hazardous waste containing solar panels at all of our utility scale solar plants, which resulted in an increase to the ARO in the amount of $14 million. In addition, due to the sale of 4CA assets to NTEC in 2018 (see Note 11 for more information on 4CA matters) there was a decrease to the ARO of $9 million. APS recognized an ARO of $7 million for rooftop solar removals in accordance with the obligations included in the customer contracts, which requires APS to remove the panels at the end of the contract life and includes the costs for the disposal of hazardous materials in accordance with environmental regulations. Finally, APS has other ARO adjustments resulting in a net decrease of $1 million.

The following table shows the change in our asset retirement obligations for 2019 and 2018 (dollars in thousands):

	2019				2018
Asset retirement obligations at the beginning of year	$	726,545			$	679,529
Changes attributable to:
Accretion expense	39,726				36,876
Settlements	(12,591		)		(9,726		)
Estimated cash flow revisions	(96,462		)		2,002
Newly incurred or acquired obligations	—				17,864
Asset retirement obligations at the end of year	$	657,218			$	726,545

 

In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.  See detail of regulatory liabilities in Note 4.

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Consolidated quarterly financial information for 2019 and 2018 is provided in the tables below (dollars in thousands, except per share amounts).  Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

	2019 Quarter Ended																2019
	March 31,				June 30,				September 30,				December 31,				Total
Operating revenues	$	740,530			$	869,501			$	1,190,787			$	670,391			$	3,471,209
Operations and maintenance	245,634				227,543				238,582				229,857				941,616
Operating income	60,084				196,589				403,290				11,997				671,960
Income taxes	2,418				17,080				53,266				(88,537		)		(15,773		)
Net income	22,791				149,019				317,149				68,854				557,813
Net income attributable to common shareholders	17,918				144,145				312,276				63,981				538,320
Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.16			$	1.28			$	2.78			$	0.57			$	4.79
Net income attributable to common shareholders — Diluted	0.16				1.28				2.77				0.57				4.77

 

	2018 Quarter Ended																2018
	March 31,				June 30,				September 30,				December 31,				Total
Operating revenues	$	692,714			$	974,123			$	1,268,034			$	756,376			$	3,691,247
Operations and maintenance	265,682				268,397				246,545				256,120				1,036,744
Operating income	31,334				242,162				433,307				66,884				773,687
Income taxes	(1,265		)		44,039				84,333				6,795				133,902
Net income	8,094				171,612				319,885				30,949				530,540
Net income attributable to common shareholders	3,221				166,738				315,012				26,076				511,047
Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.03			$	1.49			$	2.81			$	0.23			$	4.56
Net income attributable to common shareholders — Diluted	0.03				1.48				2.80				0.23				4.54

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Selected Quarterly Financial Data (Unaudited) - APS

 

APS's quarterly financial information for 2019 and 2018 is as follows (dollars in thousands):

 

	2019 Quarter Ended																2019
	March 31,				June 30,				September 30,				December 31,				Total
Operating revenues	$	740,530			$	869,501			$	1,190,787			$	670,391			$	3,471,209
Operations and maintenance	240,375				224,143				235,440				226,758				926,716
Operating income	65,377				200,018				406,465				15,124				686,984
Net income attributable to common shareholder	28,276				150,176				318,870				67,949				565,271

 

	2018 Quarter Ended																2018
	March 31,				June 30,				September 30,				December 31,				Total
Operating revenues	$	692,006			$	971,963			$	1,267,997			$	756,376			$	3,688,342
Operations and maintenance	254,601				251,999				226,346				236,281				969,227
Operating income	37,878				251,590				453,547				86,753				829,768
Net income attributable to common shareholder	9,599				177,825				338,366				44,475				570,265

 

We classify our assets and liabilities that are carried at fair value within the fair value hierarchy.  This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories.  The three levels of the fair value hierarchy are:

 

Level 1 — Unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves). 

 

Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity.  Instruments in this category include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist.  The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.

 

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable.  We maximize the use of observable inputs and minimize the use of unobservable inputs.  We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities.  If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use.  Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels.  We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity,

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and assessing the volume of transactions.  We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

Certain instruments have been valued using the concept of NAV, as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements

 

We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trust and other special use funds. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans.  See Note 8 for fair value discussion of plan assets held in our retirement and other benefit plans.

 

Cash Equivalents

 

Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets.

Risk Management Activities — Derivative Instruments

 

Exchange traded commodity contracts are valued using unadjusted quoted prices.  For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value.  We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments.  These include valuation adjustments for liquidity and credit risks.  The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged.  The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio.  We maintain credit policies that management believes minimize overall credit risk.

 

Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions.  Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction.  We rely primarily on broker quotes to value these instruments.  When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance.  These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity.  When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.

 

When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3.  Our classification of instruments as Level 3 is primarily reflective of the long-term nature of our energy transactions.

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Our energy risk management committee, consisting of officers and key management personnel, oversees our energy risk management activities to ensure compliance with our stated energy risk management policies.  We have a risk control function that is responsible for valuing our derivative commodity instruments in accordance with established policies and procedures.  The risk control function reports to the chief financial officer’s organization.

 

Investments Held in Nuclear Decommissioning Trust and Other Special Use Funds

 

The nuclear decommissioning trust and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union medical trust. See Note 20 for additional discussion about our investment accounts.

We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent's internal operating controls and valuation processes.

Fixed Income Securities

Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1.  Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves.  These fixed income instruments are classified as Level 2.  Whenever possible, multiple market quotes are obtained which enables a cross-check validation.  A primary price source is identified based on asset type, class, or issue of securities.

Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short term instruments. These instruments are valued using active market prices or utilizing observable inputs described above.

Equity Securities

The nuclear decommissioning trust's equity security investments are held indirectly through commingled funds.  The commingled funds are valued using the funds' NAV as a practical expedient. The funds' NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV.  The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index.  Because the commingled funds' shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.

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The nuclear decommissioning trust and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid, investments are valued using active market prices.

 Fair Value Tables

 

The following table presents the fair value at December 31, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

	Level 1				Level 2				Level 3				Other						Total
Assets
Risk management activities — derivative instruments:
Commodity contracts	$	—			$	551			$	33			$	(69	)		(a)		$	515
Nuclear decommissioning trust:
Equity securities	10,872				—				—				2,401				(b)		13,273
U.S. commingled equity funds	—				—				—				518,844				(c)		518,844
U.S. Treasury debt	160,607				—				—				—						160,607
Corporate debt	—				115,869				—				—						115,869
Mortgage-backed securities	—				118,795				—				—						118,795
Municipal bonds	—				73,040				—				—						73,040
Other fixed income	—				10,347				—				—						10,347
Subtotal nuclear decommissioning trust	171,479				318,051				—				521,245						1,010,775
Other special use funds:
Equity securities	7,142				—				—				474				(b)		7,616
U.S. Treasury debt	232,848				—				—				—						232,848
Municipal bonds	—				4,631				—				—						4,631
Subtotal other special use funds	239,990				4,631				—				474						245,095
Total assets	$	411,469			$	323,233			$	33			$	521,650					$	1,256,385
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—			$	(67,992	)		$	(3,429	)		$	(711	)		(a)		$	(72,132	)

(a)	Represents counterparty netting, margin, and collateral. See Note 17.

(b)	Represents net pending securities sales and purchases.

(c)	Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

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 The following table presents the fair value at December 31, 2018 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):

 

	Level 1				Level 2				Level 3				Other						Total
Assets
Cash equivalents	$	1,200			$	—			$	—			$	—					$	1,200
Risk management activities — derivative instruments:
Commodity contracts	—				3,140				2				(2,029		)		(a)		1,113
Nuclear decommissioning trust:
Equity securities	5,203				—				—				2,148				(b)		7,351
U.S. commingled equity funds	—				—				—				396,805				(c)		396,805
U.S. Treasury debt	148,173				—				—				—						148,173
Corporate debt	—				96,656				—				—						96,656
Mortgage-backed securities	—				113,115				—				—						113,115
Municipal bonds	—				79,073				—				—						79,073
Other fixed income	—				9,961				—				—						9,961
Subtotal nuclear decommissioning trust	153,376				298,805				—				398,953						851,134
Other special use funds:
Equity securities	45,130				—				—				593				(b)		45,723
U.S. Treasury debt	173,310				—				—				—						173,310
Municipal bonds	—				17,068				—				—						17,068
Subtotal other special use funds	218,440				17,068				—				593						236,101
Total assets	$	373,016			$	319,013			$	2			$	397,517					$	1,089,548
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—			$	(52,696	)		$	(8,216	)		$	875			(a)		$	(60,037	)

(a)	Represents counterparty netting, margin, and collateral. See Note 17.

(b)	Represents net pending securities sales and purchases.

(c)	Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

 

Fair Value Measurements Classified as Level 3

 

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote.  Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements.  Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4).

 

Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the

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related contracts.  Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.

Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.

 

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2019 and December 31, 2018:

 

	December 31, 2019 Fair Value (thousands)								Valuation Technique		Significant Unobservable Input		Range		Weighted-Average
Commodity Contracts	Assets				Liabilities
Electricity:
Forward Contracts (a)	$	33			$	819			Discounted cash flows		Electricity forward price (per MWh)		$22.18 - $22.18		$	22.18
Natural Gas:
Forward Contracts (a)	—				2,610				Discounted cash flows		Natural gas forward price (per MMBtu)		$2.33 -$ 2.78		$	2.49
Total	$	33			$	3,429

(a)	Includes swaps and physical and financial contracts.

 

	December 31, 2018 Fair Value (thousands)								Valuation Technique		Significant Unobservable Input		Range		Weighted-Average
Commodity Contracts	Assets				Liabilities
Electricity:
Forward Contracts (a)	$	—			$	2,456			Discounted cash flows		Electricity forward price (per MWh)		$17.88 - $37.03		$	26.10
Natural Gas:
Forward Contracts (a)	2				5,760				Discounted cash flows		Natural gas forward price (per MMBtu)		$1.79 - $2.92		$	2.48
Total	$	2			$	8,216

(a)	Includes swaps and physical and financial contracts.

 

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The following table shows the changes in fair value for our risk management activities' assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the years ended December 31, 2019 and 2018 (dollars in thousands):

 

		Year Ended December 31,
Commodity Contracts		2019				2018
Net derivative balance at beginning of period		$	(8,214	)		$	(18,256	)
Total net gains (losses) realized/unrealized:
Included in earnings		—				—
Included in OCI		—				—
Deferred as a regulatory asset or liability		(13,457		)		(1,130		)
Settlements		12,250				(787		)
Transfers into Level 3 from Level 2		(6,512		)		(12,830		)
Transfers from Level 3 into Level 2		12,537				24,789
Net derivative balance at end of period		$	(3,396	)		$	(8,214	)
Net unrealized gains included in earnings related to instruments still held at end of period		$	—			$	—

 

Transfers between levels in the fair value hierarchy shown in the table above reflect the fair market value at the beginning of the period and are triggered by a change in the lowest significant input as of the end of the period.  We had no significant Level 1 transfers to or from any other hierarchy level.  Transfers in or out of Level 3 are typically related to our long-dated energy transactions that extend beyond available quoted periods.

 

Financial Instruments Not Carried at Fair Value

 

The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. See Note 7 for our long-term debt fair values. The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9% per annum and has a book value of $44.3 million as of December 31, 2019, as presented on the Consolidated Balance Sheets.  The carrying amount is not materially different from the fair value of the note receivable and is classified within Level 3 of the fair value hierarchy.  See Note 11 for more information on 4CA matters.

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The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share for continuing operations attributable to common shareholders for the years ended December 31, 2019, 2018 and 2017 (in thousands, except per share amounts):

	2019				2018				2017
Net income attributable to common shareholders	$	538,320			$	511,047			$	488,456
Weighted average common shares outstanding — basic	112,443				112,129				111,839
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	315				421				528
Weighted average common shares outstanding — diluted	112,758				112,550				112,367
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic	$	4.79			$	4.56			$	4.37
Net income attributable to common shareholders - diluted	$	4.77			$	4.54			$	4.35

 

Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key-employees, and non-officer members of the Board of Directors. Awards granted under the 2012 Long-Term Incentive Plan (“2012 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights.  The 2012 Plan authorizes up to 4.6 million common shares to be available for grant.  As of December 31, 2019, 1.6 million common shares were available for issuance under the 2012 Plan. During 2019, 2018, and 2017, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan.

Stock-Based Compensation Expense and Activity

 

Compensation cost included in net income for stock-based compensation plans was $18 million in 2019, $20 million in 2018, and $21 million in 2017.  The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $7 million in 2019, $7 million in 2018, and $15 million in 2017.

As of December 31, 2019, there were approximately $9 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years. 

The total fair value of shares vested was $21 million in 2019, $24 million in 2018 and $22 million in 2017.

 

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The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2019, 2018 and 2017:

	Restricted Stock Units, Stock Grants, and Stock Units (a)												Performance Shares (b)
	2019				2018				2017				2019				2018				2017
Units granted	109,106				132,997				161,963				142,874				171,708				147,706
Weighted-average grant date fair value	$	89.15			$	77.51			$	72.60			$	92.16			$	76.56			$	78.99

(a)	Units granted includes awards that will be cash settled of 48,972 in 2019, 66,252 in 2018, and 67,599 in 2017.

(b)	Reflects the target payout level.

 

The following table is a summary of the status of non-vested awards as of December 31, 2019 and changes during the year:

	Restricted Stock Units, Stock Grants, and Stock Units							Performance Shares
	Shares			Weighted-Average Grant Date Fair Value				Shares (b)			Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2019	270,991			$	74.39			312,384			$	77.67
Granted	109,106			89.15				142,874			92.16
Vested	(132,102	)		73.48				(139,214	)		78.99
Forfeited (c)	(5,383	)		80.10				(9,074	)		81.03
Nonvested at December 31, 2019	242,612		(a)	81.38				306,970			83.65
Vested Awards Outstanding at December 31, 2019	67,148							139,214

 

(a)	Includes 141,621 of awards that will be cash settled.

(b)	The nonvested performance shares are reflected at target payout level.

(c)	We account for forfeitures as they occur.

Share-based liabilities paid relating to restricted stock units were $5 million, $4 million and $4 million in 2019, 2018 and 2017, respectively. This includes cash used to settle restricted stock units of $5 million, $5 million and $4 million in 2019, 2018 and 2017, respectively. Restricted stock units that are cash settled are classified as liability awards. All performance shares are classified as equity awards.

 

Restricted Stock Units, Stock Grants, and Stock Units

 

Restricted stock units are granted to officers and key employees.  Restricted stock units typically vest and settle in equal annual installments over a 4-year period after the grant date.  Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the employee's retirement. Awardees elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock. Restricted stock unit awards typically include a dividend equivalent feature. This feature allows each award to accrue dividend rights equal to the dividends they would have received had they directly owned the stock. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares.

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In December 2012, the Company granted a retention award of 50,617 performance-linked restricted stock units to the Chairman of the Board and Chief Executive Officer of Pinnacle West.  This award vested on December 31, 2016, because he remained employed with the Company through that date.  The Board did increase the number of awards that vested by 33,745 restricted stock units, payable in stock because certain performance requirements were met. In February 2017, 84,362 restricted stock units were released.

Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company's closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award.

 

Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant.  The members of the Board of Directors who elect to defer may elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock.  Each stock unit is convertible to one share of stock. The stock units accrue dividend rights, equal to the amount of dividends the Directors would have received had they directly owned stock equal to the number of vested restricted stock units or stock units from the date of grant to the date of payment, plus interest compounded quarterly.  The dividends and interest are paid, based on the Director’s election, in either stock, cash, or 50% in cash and 50% in stock.

 

Performance Share Awards

 

Performance share awards are granted to officers and key employees.  The awards contain two separate performance criteria that affect the number of shares that may be received if after the end of a 3-year performance period the performance criteria are met. For the first criteria, the number of shares that will vest is based on non-financial performance metrics (i.e., the metric component). The other criteria is based upon Pinnacle West's total shareholder return ("TSR") in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). The exact number of shares issued will vary from 0% to 200% of the target award.  Shares received include dividend rights paid in stock equal to the amount of dividends that recipients would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly. If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares.

 

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Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and interest rates.  Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps.  As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and fuels.  Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions.  The changes in market value of such instruments have a high correlation to price changes in the hedged transactions.  Derivative instruments are also entered into for economic hedging purposes.  While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges.  Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

  

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value.  See Note 14 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.

As of December 31, 2019 and 2018, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):

 

			Quantity
Commodity		Unit of Measure	December 31, 2019			December 31, 2018
Power		GWh	193			250
Gas		Billion cubic feet	257			218

 

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Gains and Losses from Derivative Instruments

 

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2019, 2018 and 2017 (dollars in thousands):

 

		Financial Statement		Year Ended December 31,
Commodity Contracts		Location		2019				2018				2017
Loss Recognized in OCI on Derivative Instruments (Effective Portion)		OCI — derivative instruments		$	—			$	—			$	(59	)
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)		Fuel and purchased power (b)		(1,512		)		(2,000		)		(3,519		)

(a)	During the years ended December 31, 2019, 2018, and 2017, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

(b)	Amounts are before the effect of PSA deferrals.

 

During the next twelve months, we estimate that a net loss of $0.8 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions.  In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

 

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2019, 2018 and 2017 (dollars in thousands):

 

		Financial Statement		Year Ended December 31,
Commodity Contracts		Location		2019				2018				2017
Net Loss Recognized in Income		Operating revenues		$	—			$	(2,557	)		$	(1,192	)
Net Loss Recognized in Income		Fuel and purchased power (a)		(84,953		)		(12,951		)		(87,991		)
Total				$	(84,953	)		$	(15,508	)		$	(89,183	)

(a)	Amounts are before the effect of PSA deferrals.

 

Derivative Instruments in the Consolidated Balance Sheets

 

Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty.  Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements.  Transactions with counterparties that have master netting arrangements are offset and reported net on the Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets.

 

We do not offset a counterparty's current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions

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to be offset in the event of a default.  Additionally, in the event of a default, our master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement.  These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit).  These types of transactions are excluded from the offsetting tables presented below.

 

As of December 31, 2017, we no longer have derivative instruments that are designated as cash flow hedging instruments.

The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of offsetting as of December 31, 2019 and 2018.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.

 

As of December 31, 2019: (dollars in thousands)		Gross  Recognized  Derivatives  (a)				Amounts  Offset (b)				Net  Recognized  Derivatives				Other  (c)				Amount  Reported on  Balance Sheet
Current assets		$	584			$	(474	)		$	110			$	405			$	515
Current liabilities		(38,235		)		474				(37,761		)		(1,185		)		(38,946		)
Deferred credits and other		(33,186		)		—				(33,186		)		—				(33,186		)
Total liabilities		(71,421		)		474				(70,947		)		(1,185		)		(72,132		)
Total		$	(70,837	)		$	—			$	(70,837	)		$	(780	)		$	(71,617	)

(a)	All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)	No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c)	Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of $405.

 

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As of December 31, 2018: (dollars in thousands)		Gross  Recognized  Derivatives  (a)				Amounts Offset  (b)				Net  Recognized  Derivatives				Other  (c)				Amount  Reported on  Balance Sheet
Current assets		$	3,106			$	(2,149	)		$	957			$	156			$	1,113
Investments and other assets		36				(36		)		—				—				—
Total assets		3,142				(2,185		)		957				156				1,113
Current liabilities		(36,345		)		2,149				(34,196		)		(1,310		)		(35,506		)
Deferred credits and other		(24,567		)		36				(24,531		)		—				(24,531		)
Total liabilities		(60,912		)		2,185				(58,727		)		(1,310		)		(60,037		)
Total		$	(57,770	)		$	—			$	(57,770	)		$	(1,154	)		$	(58,924	)

(a)	All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)	No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c)	Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.

Credit Risk and Credit Related Contingent Features

 

We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of December 31, 2019, Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

 

Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).

 

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The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2019 (dollars in thousands):

 

	December 31, 2019
Aggregate fair value of derivative instruments in a net liability position	$	71,116
Cash collateral posted	—
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	70,519

(a)	This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

 

We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $95 million if our debt credit ratings were to fall below investment grade.

 

The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2019, 2018 and 2017 (dollars in thousands):

 

	2019				2018				2017
Other income:
Interest income	$	10,377			$	8,647			$	3,497
Debt return on Four Corners SCR deferral (Note 4)	19,541				16,153				354
Debt return on Ocotillo modernization project (Note 4)	20,282				—				—
Miscellaneous	63				96				155
Total other income	$	50,263			$	24,896			$	4,006
Other expense:
Non-operating costs	$	(10,663	)		$	(10,076	)		$	(11,749	)
Investment losses — net	(1,835		)		(417		)		(4,113		)
Miscellaneous	(5,382		)		(7,473		)		(5,677		)
Total other expense	$	(17,880	)		$	(17,966	)		$	(21,539	)

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Other Income and Other Expense - APS

 

The following table provides detail of APS’s other income and other expense for 2019, 2018 and 2017 (dollars in thousands):

 

	2019				2018				2017
Other income:
Interest income	$	6,998			$	6,496			$	2,504
Debt return on Four Corners SCR deferral (Note 4)	19,541				16,153				354
Debt return on Ocotillo modernization project (Note 4)	20,282				—				—
Miscellaneous	63				97				155
Total other income	$	46,884			$	22,746			$	3,013
Other expense:
Non-operating costs	$	(9,612	)		$	(9,462	)		$	(10,825	)
Miscellaneous	(3,378		)		(5,830		)		(3,088		)
Total other expense	$	(12,990	)		$	(15,292	)		$	(13,913	)

 

In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities.  APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2020 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

 

The leases' terms give APS the ability to utilize the assets for a significant portion of the assets' economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs' economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $19 million for 2019, 2018 and 2017. The increase in net income is entirely attributable to the noncontrolling interests.  Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

    

Our Consolidated Balance Sheets at December 31, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands):

 

	December 31, 2019				December 31, 2018
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	101,906			$	105,775
Equity-Noncontrolling interests	122,540				125,790

 

Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders.  These assets are reported on our consolidated financial statements.

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APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur.  Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value.  If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $301 million beginning in 2020, and up to $456 million over the lease extension term.

 

For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.

 

We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Accounts, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security investments at their fair value on our Consolidated Balance Sheets. See Note 14 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

Nuclear Decommissioning Trusts - To fund the future costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations.  Third-party investment managers are authorized to buy and sell securities per stated investment guidelines.  The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments) in other regulatory liabilities.

 

Coal Reclamation Escrow Account - APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including other-than-temporary impairments) in other regulatory liabilities. Activities relating to APS coal reclamation escrow account investments are included within the other special use funds in the table below.

Active Union Employee Medical Account - APS has investments restricted for paying active union employee medical costs. These investments were transferred from APS other postretirement benefit trust assets into the active union employee medical trust in January 2018. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In August 2019, the Company was reimbursed $15 million for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including other-than-temporary impairments) in other regulatory liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the tables below.

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APS

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's nuclear decommissioning trust and other special use fund assets at December 31, 2019 and December 31, 2018 (dollars in thousands): 

	December 31, 2019
	Fair Value												Total Unrealized Gains				Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts				Other Special Use Funds				Total
Equity Securities	$	529,716			$	7,142			$	536,858			$	337,681			$	—
Available for Sale-Fixed Income Securities	478,658				237,479				716,137			(a)	25,795				(669		)
Other	2,401				474				2,875			(b)	—				—
Total	$	1,010,775			$	245,095			$	1,255,870			$	363,476			$	(669	)

(a)	As of December 31, 2019, the amortized cost basis of these available-for-sale investments is $691 million.

(b)	Represents net pending securities sales and purchases.

	December 31, 2018
	Fair Value												Total Unrealized Gains				Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts				Other Special Use Funds				Total
Equity Securities	$	402,008			$	45,130			$	447,138			$	222,147			$	(459	)
Available for Sale-Fixed Income Securities	446,978				190,378				637,356			(a)	8,634				(6,778		)
Other	2,148				593				2,741			(b)	—				—
Total	$	851,134			$	236,101			$	1,087,235			$	230,781			$	(7,237	)

(a)	As of December 31, 2018, the amortized cost basis of these available-for-sale investments is $635 million.

(b)	Represents net pending securities sales and purchases.

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The following table sets forth APS's realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the years ended December 31, 2019, 2018 and 2017 (dollars in thousands):

 

	Year Ended December 31,
	Nuclear Decommissioning Trusts				Other Special Use Funds				Total
2019
Realized gains	$	11,024			$	108			$	11,132
Realized losses	(6,972		)		—				(6,972		)
Proceeds from the sale of securities (a)	473,806				245,228				719,034
2018
Realized gains	6,679				1				6,680
Realized losses	(13,552		)		—				(13,552		)
Proceeds from the sale of securities (a)	554,385				98,648				653,033
2017
Realized gains	21,813				17				21,830
Realized losses	(13,146		)		(9		)		(13,155		)
Proceeds from the sale of securities (a)	542,246				4,093				546,339

(a)	Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union trust.

    

Fixed Income Securities Contractual Maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2019 is as follows (dollars in thousands):

 

	Nuclear Decommissioning Trusts				Coal Reclamation Escrow Account				Active Union Medical Trust				Total
Less than one year	$	26,984			$	31,953			$	40,449			$	99,386
1 year – 5 years	136,139				25,229				138,042				299,410
5 years – 10 years	105,797				—				—				105,797
Greater than 10 years	209,738				1,806				—				211,544
Total	$	478,658			$	58,988			$	178,491			$	716,137

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The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2019 and 2018 (dollars in thousands): 

	Pension and Other Postretirement Benefits						Derivative Instruments						Total
Balance December 31, 2017	$	(42,440	)				$	(2,562	)				$	(45,002	)
OCI (loss) before reclassifications	102						(78		)				24
Amounts reclassified from accumulated other comprehensive loss	4,295				(a)		1,527				(b)		5,822
Reclassification of income tax effect related to tax reform	(7,954		)				(598		)				(8,552		)
Balance December 31, 2018	(45,997		)				(1,711		)				(47,708		)
OCI (loss) before reclassifications	(14,041		)				—						(14,041		)
Amounts reclassified from accumulated other comprehensive loss	3,516				(a)		1,137				(b)		4,653
Balance December 31, 2019	$	(56,522	)				$	(574	)				$	(57,096	)

(a)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

(b)	These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

Changes in Accumulated Other Comprehensive Loss - APS

 

The following table shows the changes in APS's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2019 and 2018 (dollars in thousands): 

	Pension and Other Postretirement Benefits						Derivative Instruments						Total
Balance December 31, 2017	$	(24,421	)				$	(2,562	)				$	(26,983	)
OCI (loss) before reclassifications	(326		)				(78		)				(404		)
Amounts reclassified from accumulated other comprehensive loss	3,791				(a)		1,527				(b)		5,318
Reclassification of income tax effect related to tax reform	(4,440		)				(598		)				(5,038		)
Balance December 31, 2018	(25,396		)				(1,711		)				(27,107		)
OCI (loss) before reclassifications	(12,572		)				—						(12,572		)
Amounts reclassified from accumulated other comprehensive loss	3,020				(a)		1,137				(b)		4,157
Balance December 31, 2019	$	(34,948	)				$	(574	)				$	(35,522	)

(a)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

(b)	These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(dollars in thousands)

 

	Year Ended December 31,
	2019				2018				2017
Operating revenues	$	—			$	—			$	119
Operating expenses	12,451				53,844				24,591
Operating loss	(12,451		)		(53,844		)		(24,472		)
Other
Equity in earnings of subsidiaries	562,946				569,249				507,495
Other expense	(3,957		)		(3,202		)		(2,422		)
Total	558,989				566,047				505,073
Interest expense	15,069				12,074				5,633
Income before income taxes	531,469				500,129				474,968
Income tax benefit	(6,851		)		(10,918		)		(13,488		)
Net income attributable to common shareholders	538,320				511,047				488,456
Other comprehensive income (loss) — attributable to common shareholders	(9,388		)		5,846				(1,180		)
Total comprehensive income — attributable to common shareholders	$	528,932			$	516,893			$	487,276

 

See Combined Notes to Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

(dollars in thousands)

 

	December 31,
	2019				2018
ASSETS
Current assets
Cash and cash equivalents	$	19			$	41
Accounts receivable	104,640				99,989
Income tax receivable	15,905				32,737
Other current assets	401				1,502
Total current assets	120,965				134,269
Investments and other assets
Investments in subsidiaries	6,067,957				5,859,834
Deferred income taxes	40,757				5,243
Other assets	50,139				34,910
Total investments and other assets	6,158,853				5,899,987
Total Assets	$	6,279,818			$	6,034,256
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	7,634			$	9,565
Accrued taxes	8,573				9,006
Common dividends payable	87,982				82,675
Short-term borrowings	114,675				76,400
Current maturities of long-term debt	450,000				—
Operating lease liabilities	81				—
Other current liabilities	15,126				19,215
Total current liabilities	684,071				196,861
Long-term debt less current maturities (Note 7)	(575		)		448,796
Pension liabilities	17,942				17,766
Operating lease liabilities	1,780				—
Other	23,412				22,128
Total deferred credits and other	43,134				39,894
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
Common stock equity
Common stock	2,650,134				2,629,440
Accumulated other comprehensive loss	(57,096		)		(47,708		)
Retained earnings	2,837,610				2,641,183
Total Pinnacle West Shareholders’ equity	5,430,648				5,222,915
Noncontrolling interests	122,540				125,790
Total Equity	5,553,188				5,348,705
Total Liabilities and Equity	$	6,279,818			$	6,034,256

 

See Combined Notes to Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2019				2018				2017
Cash flows from operating activities
Net income	$	538,320			$	511,047			$	488,456
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(562,946		)		(569,249		)		(507,495		)
Depreciation and amortization	76				76				76
Deferred income taxes	(35,831		)		49,535				(264		)
Accounts receivable	182				(7,881		)		(2,106		)
Accounts payable	(2,129		)		1,967				(11,162		)
Accrued taxes and income tax receivables — net	16,400				(13,535		)		(22,247		)
Dividends received from subsidiaries	336,300				316,000				296,800
Other	(1,300		)		31,807				15,092
Net cash flow provided by operating activities	289,072				319,767				257,150
Cash flows from investing activities
Investments in subsidiaries	1,557				(142,796		)		(178,027		)
Repayments of loans from subsidiaries	4,190				6,477				2,987
Advances of loans to subsidiaries	(4,165		)		(500		)		(6,388		)
Net cash flow provided by (used for) investing activities	1,582				(136,819		)		(181,428		)
Cash flows from financing activities
Issuance of long-term debt	—				150,000				298,761
Short-term debt borrowings under revolving credit facility	49,000				20,000				58,000
Short-term debt repayments under revolving credit facility	(65,000		)		(32,000		)		(32,000		)
Commercial paper - net	54,275				(7,000		)		27,700
Dividends paid on common stock	(329,643		)		(308,892		)		(289,793		)
Repayment of long-term debt	—				—				(125,000		)
Common stock equity issuance - net of purchases	692				(5,055		)		(13,390		)
Other	—				(1		)		—
Net cash flow used for financing activities	(290,676		)		(182,948		)		(75,722		)
Net decrease in cash and cash equivalents	(22		)		—				—
Cash and cash equivalents at beginning of year	41				41				41
Cash and cash equivalents at end of year	$	19			$	41			$	41

     See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.

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SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)

 

Column A		Column B				Column C								Column D				Column E
						Additions
Description		Balance at beginning of period				Charged to cost and expenses				Charged to other accounts				Deductions				Balance at end of period
Reserve for uncollectibles:
2019		$	4,069			$	11,819			$	—			$	7,717			$	8,171
2018		2,513				10,870				—				9,314				4,069
2017		3,037				6,836				—				7,360				2,513

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ARIZONA PUBLIC SERVICE COMPANY

SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)

 

Column A		Column B				Column C								Column D				Column E
						Additions
Description		Balance at beginning of period				Charged to cost and expenses				Charged to other accounts				Deductions				Balance at end of period
Reserve for uncollectibles:
2019		$	4,069			$	11,819			$	—			$	7,717			$	8,171
2018		2,513				10,870				—				9,314				4,069
2017		3,037				6,836				—				7,360				2,513

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(a)

This amount includes shares subject to outstanding performance share awards and restricted stock unit awards at the maximum amount of shares issuable under such awards.  However, payout of the performance share awards is contingent on the Company reaching certain levels of performance during a three-year performance period.  If the performance criteria for these awards are not fully satisfied, the award recipient will receive less than the maximum number of shares available under these grants and may receive nothing from these grants.

(b)	The weighted-average exercise price in this column does not take performance share awards or restricted stock unit awards into account, as those awards have no exercise price.

(c)

Awards under the 2012 Plan can take the form of options, stock appreciation rights, restricted stock, performance shares, performance share units, performance cash, stock grants, stock units, dividend equivalents, and restricted stock units.  Additional shares cannot be awarded under the 2007 Plan.  However, if an award under the 2012 Plan is forfeited, terminated or canceled or expires, the shares subject to such award, to the extent of the forfeiture, termination, cancellation or expiration, may be added back to the shares available for issuance under the 2012 Plan.

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