| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (b) | In 2018, the Company adopted new accounting guidance | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING (ARIZONA PUBLIC SERVICE COMPANY)PINNACLE WEST CAPITAL CORPORATION)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company.Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2019.2021. The effectiveness of our internal control over financial reporting as of December 31, 20192021, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements. February 21, 202025, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Arizona Public Service Company | | | | | | | | | | | | | 2021 | | 2020 | Net cash flow provided by operating activities | $ | 865 | | | $ | 929 | | Net cash flow used for investing activities | (1,391) | | | (1,286) | | Net cash flow provided by financing activities | 478 | | | 404 | | Net increase (decrease) in cash and cash equivalents | $ | (48) | | | $ | 47 | |
Operating Cash Flows 2021 Compared with 2020. Pinnacle West’s consolidated net cash provided by operating activities was $860 million in 2021 compared to $967 million in 2020, a decrease of $107 million in net cash provided primarily due to $252 million higher fuel and purchased power costs, $93 million higher payments for operations and maintenance costs, $15 million higher other taxes and $11 million higher interest payments, partially offset by $175 million higher cash receipts from electric revenues and $93 million other changes in working capital. The difference between APS and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s income tax cash payments to Pinnacle West and other changes in working capital.
Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. Pinnacle West also sponsors other postretirement benefit plans for the employees of Pinnacle West and its subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations. Under ERISA, the qualified pension plan was estimated to be 138% funded as of January 1, 2022, and was 131% as of January 1, 2021. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $100 million in 2021, $100 million in 2020, and $150 million in 2019. The minimum required contributions for the pension plan are zero for the next three years and we do not expect to make any voluntary contributions in 2022, 2023 or 2024. Regarding contributions to our other postretirement benefit plan, we did not make any contributions in 2021 or 2020 and do not expect to make any contributions in 2022, 2023 or 2024. The Company was reimbursed $24 million in 2021, $26 million in 2020, and $30 million in 2019 for prior years retiree medical claims from the other postretirement benefit plan trust assets. We continually monitor financial market volatility and its impact on our retirement plans and other postretirement benefits, but we believe, our liability driven investment strategy helps to minimize the impact of market volatility on our plan’s funded status. For instance, our pension plan’s funded status, as measured for accounting principles generally accepted in the United States of America (“GAAP”) purposes, is still above 107% funded as of December 31, 2021, and our postretirement benefit plans have a funded status, also as measured for GAAP purposes at December 31, 2021, in excess of 145%. See Note 8 for additional details.
The Coronavirus Aid, Relief, and Economic Security (CARES) Act allows employers to defer payments of the employer share of Social Security payroll taxes that would have otherwise been owed from March 27, 2020, through December 31, 2020. We deferred the cash payment of the employer’s portion of Social Security payroll taxes for the period July 1, 2020, through December 31, 2020 that was approximately $18 million. We paid approximately $9 million on December 28, 2021, and will pay the second half of this cash deferral by December 31, 2022.
Investing Cash Flows
2021 Compared with 2020. Pinnacle West’s consolidated net cash used for investing activities was $1,387 million in 2021 compared to $1,278 million in 2020, an increase of $109 million in net cash used primarily related to increased capital expenditures.
Capital Expenditures. The following table summarizes the estimated capital expenditures for the next three years: Capital Expenditures (dollars in millions) | | | | | | | | | | | | | | | | | | | | | Estimated for the Year Ended December 31, | | 2022 | | 2023 | | 2024 | | | APS | | | | | | | | Generation: | | | | | | | | Clean: | | | | | | | | Nuclear Generation | $ | 110 | | | $ | 120 | | | $ | 110 | | | | | | | | | | | | Renewables and Energy Storage Systems (“ESS”) (a) | 230 | | | 210 | | | 450 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other Generation (b) | 250 | | | 270 | | | 190 | | | | Distribution | 510 | | | 530 | | | 500 | | | | Transmission | 250 | | | 210 | | | 210 | | | | Other (c) | 175 | | | 185 | | | 190 | | | | Total APS | $ | 1,525 | | | $ | 1,525 | | | $ | 1,650 | | | |
(a)APS Solar Communities program, energy storage, renewable projects, and other clean energy projects. (b)Includes generation environmental projects. (c)Primarily information systems and facilities projects. The table above does not include capital expenditures related to BCE projects.
Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and ESS. Generation capital expenditures also include improvements to existing fossil plants. Examples of the types of projects included in the forecast of generation capital expenditures are additions of renewables and energy storage, and upgrades and capital replacements of various nuclear and fossil power plant equipment, such as turbines, boilers, and environmental equipment. We are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.
Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.
Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock. Financing Cash Flows and Liquidity 2021 Compared with 2020. Pinnacle West’s consolidated net cash provided by financing activities was $477 million in 2021 compared to $361 million of net cash provided in 2020, an increase of $116 million in net cash provided by financing activities primarily due to $915 million lower long-term debt
repayments, partially offset by $850 million in lower issuances of long-term debt, a net increase in short-term borrowings of $69 million and higher dividend payments of $19 million.
APS’s consolidated net cash provided by financing activities was $478 million in 2021 compared to $404 million in 2020, an increase of $74 million in net cash provided by financing activities primarily due to $465 million lower long-term debt repayments, offset by $653 million in lower issuances of long-term debt, a net increase in short-term borrowings of $279 million, and higher dividend payments of $19 million.
Significant Financing Activities. On December 15, 2021, the Pinnacle West Board of Directors declared a dividend of $0.85 per share of common stock, payable on March 1, 2022, to shareholders of record on February 1, 2022. During 2021, Pinnacle West increased its indicated annual dividend from $3.32 per share to $3.40 per share. For the year ended December 31, 2021, Pinnacle West’s total dividends paid per share of common stock were $3.34 per share, which resulted in dividend payments of $369 million.
Available Credit Facilities. Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper. See Note 6 for more information on available credit facilities.
Other Financing Matters. See Note 16 for information related to the change in our margin and collateral accounts. 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 these covenants. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2021, the ratio was approximately 56% for Pinnacle West and 50% 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.
On December 17, 2020, the ACC issued a financing order that, subject to specified parameters and procedures, increased APS’s long-term debt limit from $5.9 billion to $7.5 billion, and authorized APS’s short-term debt authorization equal to the 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 further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as ofFebruary 17, 2022, are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. On October 12, 2021, Fitch Ratings downgraded the issuer ratings of the Company and APS from A- to BBB+ and the senior unsecured ratings of the Company and APS from A- and A to BBB+ and A-, respectively, with a negative outlook retained.Fitch Ratings also affirmed the commercial paper ratings of the Company and APS at F2.On November 9, 2021, S&P downgraded the issuer ratings of the Company and APS from A- to BBB+.S&P also downgraded the senior unsecured ratings of the Company and APS from BBB+ to BBB and A- to BBB+, respectively, with a negative outlook retained.Commercial paper ratings remained unchanged at A-2 for both entities.On November 17, 2021, Moody’s downgraded both the issuer and senior unsecured ratings of the Company from A3 to Baa1.Concurrently, Moody’s downgraded the issuer and senior unsecured ratings of APS from A2 to A3.Commercial paper for APS was downgraded from P-1 to P-2.The commercial paper ratings for the Company remain unchanged.The outlooks for both companies are negative.At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings. | | | | | | | | | | | | | | | | | | | Moody’s | | Standard & Poor’s | | Fitch | Pinnacle West | | | | | | Corporate credit rating | Baa1 | | BBB+ | | BBB+ | Senior unsecured | Baa1 | | BBB | | BBB+ | Commercial paper | P-2 | | A-2 | | F2 | Outlook | Negative | | Negative | | Negative | | | | | | | | | | | | | APS | | | | | | Corporate credit rating | A3 | | BBB+ | | BBB+ | Senior unsecured | A3 | | BBB+ | | A- | Commercial paper | P-2 | | A-2 | | F2 | Outlook | Negative | | Negative | | Negative |
Contractual Obligations
Pinnacle West has contractual obligations and other commitments that will need to be funded in the future, in addition to its capital expenditure programs. Material contractual obligations and other commitments are as follows:
•Pinnacle West and APS have material long-term debt obligations that mature at various dates through 2050 and bear interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2021. See Note 7.
•Pinnacle West and APS maintain committed revolving credit facilities. See Note 6 for short-term debt details.
•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. Purchase obligations includes capital expenditures and other obligations. See Note 11. Commitments related to purchased power lease contracts are also considered fuel and purchased power commitments. See Note 9.
•APS holds certain contracts to purchase renewable energy credits in compliance with the RES. See Notes 4 and 11.
•APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. See Note 11.
•APS is required to make payments to the noncontrolling interests related to the Palo Verde sale leaseback through 2033. See Note 18. CRITICAL ACCOUNTING POLICIES In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an 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, except for pension benefits, which would be charged to OCI and result in lower future earnings. Management judgments also include assessing the impact of potential ACC or FERC Commission-ordered refunds to customers on regulatory liabilities. We had $1,712 million of regulatory assets and $2,795 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2021. See Notes 1 and 4 for more information.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit assets, liabilities and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2021, reported pension assets and liabilities on the Consolidated Balance Sheets and our 2021 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions): | | | | | | | | | | | | | | | | | Increase (Decrease) | Actuarial Assumption (a) | | Impact on Pension Plans | | Impact on Pension Expense | Discount rate: | | | | | Increase 1% | | $ | (388) | | | $ | 5 | | Decrease 1% | | 471 | | | 15 | | Expected long-term rate of return on plan assets: | | | | | Increase 1% | | — | | | (28) | | Decrease 1% | | — | | | 28 | |
(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2021, other postretirement benefit obligation and our 2021 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions): | | | | | | | | | | | | | | | | | Increase (Decrease) | Actuarial Assumption (a) | | Impact on Other Postretirement Benefit Plans | | Impact on Other Postretirement Benefit Expense | Discount rate: | | | | | Increase 1% | | $ | (72) | | | $ | (4) | | Decrease 1% | | 90 | | | 5 | | Healthcare cost trend rate (b): | | | | | Increase 1% | | 80 | | | 8 | | Decrease 1% | | (65) | | | (7) | | Expected long-term rate of return on plan assets – pretax: | | | | | Increase 1% | | — | | | (6) | | Decrease 1% | | — | | | 6 | |
(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.
See Note 8 for further details about our pension and other postretirement benefit plans.
Fair Value Measurements
We account for derivative instruments, investments held in our nuclear decommissioning trusts fund, investments held in our other special use funds, certain cash equivalents, and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use inputs, or assumptions that market participants would use, to determine fair market value. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The significance of a particular input determines how the instrument is classified in a fair value hierarchy. The determination of fair value sometimes requires subjective and complex judgment. Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within a fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 1 for a discussion of accounting policies and Note 13 for fair value measurement disclosures.
Asset Retirement Obligations
We recognize an ARO for the future decommissioning or retirement of our tangible long-lived assets for which a legal obligation exists. The ARO liability represents an estimate of the fair value of the current obligation related to decommissioning and the retirement of those assets. ARO measurements inherently involve uncertainty in the amount and timing of settlement of the liability. We use an expected cash flow approach to measure the amount we recognize as an ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios
consider settlement of the ARO at the expiration of the asset’s current license or lease term and expected decommissioning dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related assets. In addition, we accrete the ARO liability to reflect the passage of time. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. In accordance with GAAP accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.
AROs as of December 31, 2021 are described further in Note 12.
OTHER ACCOUNTING MATTERS
In July 2021, a new accounting standard, ASU 2021-05, was issued that amends lessor’s accounting treatment for certain lease transactions with variable lease payments. We adopted the standard on January 1, 2022 using a prospective approach. The adoption of this standard did not impact our financial statements. See Note 3 for additional information.
MARKET AND CREDIT RISKS Market Risks Our operations include managing market risks related to changes in interest rates, commodity prices, investments held by our nuclear decommissioning trust, other special use funds and benefit plan assets. Interest Rate and Equity Risk We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust, other special use funds (see Note 13 and Note 19), and benefit plan assets. The nuclear decommissioning trust, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.
The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2021, and 2020. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2021, and 2020 (dollars in millions): Pinnacle West – Consolidated | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Short-Term Debt | | Variable-Rate Long-Term Debt | | Fixed-Rate Long-Term Debt | | | Interest | | | | Interest | | | | Interest | | | 2021 | | Rates | | Amount | | Rates | | Amount | | Rates | | Amount | 2022 | | 0.18 | % | | $ | 292 | | | 0.78 | % | | $ | 150 | | | — | | | $ | — | | 2023 | | — | | | — | | | — | | | — | | | — | | | — | | 2024 | | — | | | — | | | 0.85 | % | | 150 | | | 3.35 | % | | 250 | | 2025 | | — | | | — | | | — | | | — | | | 1.99 | % | | 800 | | 2026 | | — | | | — | | | — | | | — | | | 2.55 | % | | 250 | | Years thereafter | | — | | | — | | | 0.22 | % | | 36 | | | 3.87 | % | | 5,480 | | Total | | | | $ | 292 | | | | | $ | 336 | | | | | $ | 6,780 | | Fair value | | | | $ | 292 | | | | | $ | 336 | | | | | $ | 7,390 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Short-Term Debt | | Variable-Rate Long-Term Debt | | Fixed-Rate Long-Term Debt | | | Interest | | | | Interest | | | | Interest | | | 2020 | | Rates | | Amount | | Rates | | Amount | | Rates | | Amount | 2021 | | 0.40 | % | | $ | 169 | | | — | | | $ | — | | | — | | | $ | — | | 2022 | | — | | | — | | | — | | | — | | | — | | | — | | 2023 | | — | | | — | | | — | | | — | | | — | | | — | | 2024 | | — | | | — | | | — | | | — | | | 3.35 | % | | 250 | | 2025 | | — | | | — | | | — | | | — | | | 1.99 | % | | 800 | | Years thereafter | | — | | | — | | | 0.18 | % | | 36 | | | 3.95 | % | | 5,280 | | Total | | | | $ | 169 | | | | | $ | 36 | | | | | $ | 6,330 | | Fair value | | | | $ | 169 | | | | | $ | 36 | | | | | $ | 7,577 | |
The tables below present contractual balances of APS’s long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2021, and 2020. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2021, and 2020 (dollars in millions): APS — Consolidated | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Short-Term Debt | | Variable-Rate Long-Term Debt | | Fixed-Rate Long-Term Debt | | | Interest | | | | Interest | | | | Interest | | | 2021 | | Rates | | Amount | | Rates | | Amount | | Rates | | Amount | 2022 | | 0.18 | % | | $ | 279 | | | — | | | $ | — | | | — | | | $ | — | | 2023 | | — | | | — | | | — | | | — | | | — | | | — | | 2024 | | — | | | — | | | — | | | — | | | 3.35 | % | | 250 | | 2025 | | — | | | — | | | — | | | — | | | 3.15 | % | | 300 | | 2026 | | — | | | — | | | — | | | — | | | 2.55 | % | | 250 | | Years thereafter | | — | | | — | | | 0.22 | % | | 36 | | | 3.87 | % | | 5,480 | | Total | | | | $ | 279 | | | | | $ | 36 | | | | | $ | 6,280 | | Fair value | | | | $ | 279 | | | | | $ | 36 | | | | | $ | 6,898 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Variable-Rate Long-Term Debt | | Fixed-Rate Long-Term Debt | | | | | | Interest | | | | Interest | | | 2020 | | | | | Rates | | Amount | | Rates | | Amount | 2021 | | | | | — | | | $ | — | | | — | | | $ | — | | 2022 | | | | | — | | | — | | | — | | | — | | 2023 | | | | | — | | | — | | | — | | | — | | 2024 | | | | | — | | | — | | | 3.35 | % | | 250 | | 2025 | | | | | — | | | — | | | 3.15 | % | | 300 | | Years thereafter | | | | | 0.18 | % | | 36 | | | 3.95 | % | | 5,280 | | Total | | | | | | | $ | 36 | | | | | $ | 5,830 | | Fair value | | | | | | | $ | 36 | | | | | $ | 7,068 | |
Commodity Price Risk We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options, and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.
The following table shows the net pretax changes in mark-to-market of our derivative positions (dollars in millions): | | | | | | | | | | | | | December 31, 2021 | | December 31, 2020 | Mark-to-market of net positions at beginning of year | $ | (13) | | | $ | (71) | | Increase in regulatory liability | 120 | | | 57 | | Recognized in OCI: | | | | | | | | Mark-to-market losses realized during the period | — | | | 1 | | Change in valuation techniques | — | | | — | | Mark-to-market of net positions at end of year | $ | 107 | | | $ | (13) | |
The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2021, by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. See Note 1, “Derivative Accounting” and “Fair Value Measurements,” for more discussion of our valuation methods. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Source of Fair Value | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Total Fair Value | Observable prices provided by other external sources | | $ | 63 | | | $ | 35 | | | $ | 12 | | | $ | — | | | $ | — | | | $ | 110 | | Prices based on unobservable inputs | | (3) | | | — | | | — | | | — | | | — | | | (3) | | Total by maturity | | $ | 60 | | | $ | 35 | | | $ | 12 | | | $ | — | | | $ | — | | | $ | 107 | |
The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets (dollars in millions): | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 Gain (Loss) | | December 31, 2020 Gain (Loss) | | Price Up 10% | | Price Down 10% | | Price Up 10% | | Price Down 10% | Mark-to-market changes reported in: | | | | | | | | Regulatory asset (liability) (a) | | | | | | | | Electricity | $ | — | | | $ | — | | | $ | 4 | | | $ | (4) | | Natural gas | 50 | | | (50) | | | 49 | | | (49) | | Total | $ | 50 | | | $ | (50) | | | $ | 53 | | | $ | (53) | |
(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.
Credit Risk We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 16 for a discussion of our credit valuation adjustment policy.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See “Market and Credit Risks” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risks.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING (PINNACLE WEST CAPITAL CORPORATION)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2021. The effectiveness of our internal control over financial reporting as of December 31, 2021, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements. February 25, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Pinnacle West Capital Corporation Phoenix, Arizona
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Arizona Public Service CompanyPinnacle West Capital Corporation and subsidiaries (the "Company"“Company”) as of December 31, 20192021 and 2018,2020, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2019,2021, the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"“financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control -— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2021, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control -— Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting — Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 4 to the financial statements.
Critical Audit Matter Description
Arizona Public Service Company (“APS”), which is a wholly-owned subsidiary of the Company, is subject to rate regulation by the Arizona Corporation Commission (the “ACC”), which has jurisdiction with respect to the rates charged by public service utilities in Arizona. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; fuel and purchased power; operations and maintenance expense; and depreciation expense.
The ACC’s rate-making policies are premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the ACC in the future will impact the accounting for regulated operations, including decisions about the amount of allowable deferred costs
and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the ACC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment. If future recovery of regulatory assets ceases to be probable or a disallowance becomes probable, it would result in a charge to earnings.
We identified Regulatory Accounting, specifically the impact of rate regulation on the financial statements, as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory rate orders on the financial statements. 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, recent rate orders specific to APS and to other regulated entities in the same jurisdiction, and likelihood of success of legal appeals. Management judgments also include assessing the impact of potential ACC-ordered refunds to customers on regulatory liabilities. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the ACC and legal bodies, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to regulatory accounting included the following, among others: •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; 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; and the implementation of new rates as ordered by the ACC. •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. •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 precedents of the ACC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory assets and liabilities for completeness. ◦We observed the ACC open meetings for the APS 2019 Retail Rate Case. We read the ACC approved decision regarding the 2019 Retail Rate Case. ◦We obtained the Company’s internally prepared memo regarding impacts of the ACC decision to rates and recorded balances. ◦We tested that new rates were implemented within the system effective December 1, 2021.
•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 precedents set by the ACC under similar circumstances.For certain regulatory assets or liabilities where management’s assessment is based on precedents established by the ACC under similar circumstances and not specifically addressed in a regulatory order, we also obtained a letter from internal legal counsel regarding their assessment. We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment. •We evaluated management’s assessment that the SCR plant investment is not probable of a partial disallowance and that the SCR deferred costs are probable of recovery. We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, reviewed the Company's internally prepared memo, and reviewed a legal letter from the Company's external counsel to assess the likelihood of recovery in future rates or of a future reduction in rates based on the ACC decision.
/s/ Deloitte & Touche LLP
Phoenix, Arizona February 21, 202025, 2022
We have served as the Company'sCompany’s auditor since 1932.
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF INCOME (dollars and shares in thousands, except per share amounts) | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | 2021 | | 2020 | | 2019 | | | | | | | OPERATING REVENUES (Note 2) | $ | 3,803,835 | | | $ | 3,586,982 | | | $ | 3,471,209 | | OPERATING EXPENSES | | | | | | Fuel and purchased power | 1,152,551 | | | 993,419 | | | 1,042,237 | | Operations and maintenance | 954,067 | | | 958,910 | | | 941,616 | | | | | | | | Depreciation and amortization | 650,875 | | | 614,378 | | | 590,929 | | Taxes other than income taxes | 234,639 | | | 224,835 | | | 218,579 | | Other expenses | 6,393 | | | 7,288 | | | 5,888 | | Total | 2,998,525 | | | 2,798,830 | | | 2,799,249 | | OPERATING INCOME | 805,310 | | | 788,152 | | | 671,960 | | OTHER INCOME (DEDUCTIONS) | | | | | | Allowance for equity funds used during construction (Note 1) | 41,737 | | | 33,776 | | | 31,431 | | Pension and other postretirement non-service credits — net (Note 8) | 112,541 | | | 56,341 | | | 22,989 | | Other income (Note 17) | 45,100 | | | 56,703 | | | 50,263 | | Other expense (Note 17) | (25,396) | | | (57,776) | | | (17,880) | | Total | 173,982 | | | 89,044 | | | 86,803 | | INTEREST EXPENSE | | | | | | Interest charges | 254,314 | | | 247,501 | | | 235,251 | | Allowance for borrowed funds used during construction (Note 1) | (21,052) | | | (18,530) | | | (18,528) | | Total | 233,262 | | | 228,971 | | | 216,723 | | INCOME BEFORE INCOME TAXES | 746,030 | | | 648,225 | | | 542,040 | | INCOME TAXES (Note 5) | 110,086 | | | 78,173 | | | (15,773) | | NET INCOME | 635,944 | | | 570,052 | | | 557,813 | | Less: Net income attributable to noncontrolling interests (Note 18) | 17,224 | | | 19,493 | | | 19,493 | | NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ | 618,720 | | | $ | 550,559 | | | $ | 538,320 | | | | | | | | WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC | 112,910 | | | 112,666 | | | 112,443 | | WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED | 113,192 | | | 112,942 | | | 112,758 | | | | | | | | EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING | | | | | | Net income attributable to common shareholders — basic | $ | 5.48 | | | $ | 4.89 | | | $ | 4.79 | | Net income attributable to common shareholders — diluted | $ | 5.47 | | | $ | 4.87 | | | $ | 4.77 | |
The accompanying notes are an integral part of the financial statements.
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (dollars in thousands) | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | 2021 | | 2020 | | 2019 | | | | | | | NET INCOME | $ | 635,944 | | | $ | 570,052 | | | $ | 557,813 | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX | | | | | | Derivative instruments: | | | | | | Net unrealized gain (loss), net of tax benefit (expense) of $(378), $662, and $0 | 1,077 | | | (2,089) | | | — | | Reclassification of net realized gain, net of tax benefit (expense) of $18, $(171), and $(375) (Note 16) | 18 | | | 592 | | | 1,137 | | Pension and other postretirement benefits activity, net of tax benefit (expense) of $(2,256), $1,371, and $3,452 (Note 8) | 6,840 | | | (4,203) | | | (10,525) | | Total other comprehensive income (loss) | 7,935 | | | (5,700) | | | (9,388) | | | | | | | | COMPREHENSIVE INCOME | 643,879 | | | 564,352 | | | 548,425 | | Less: Comprehensive income attributable to noncontrolling interests | 17,224 | | | 19,493 | | | 19,493 | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ | 626,655 | | | $ | 544,859 | | | $ | 528,932 | |
The accompanying notes are an integral part of the financial statements.
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED BALANCE SHEETS (dollars in thousands) | | | | | | | | | | | | | December 31, | | 2021 | | 2020 | ASSETS | | | | | | | | CURRENT ASSETS | | | | Cash and cash equivalents | $ | 9,969 | | | $ | 59,968 | | Customer and other receivables | 391,923 | | | 313,576 | | Accrued unbilled revenues | 133,980 | | | 132,197 | | Allowance for doubtful accounts (Note 2) | (25,354) | | | (19,782) | | Materials and supplies (at average cost) | 349,135 | | | 314,745 | | Fossil fuel (at average cost) | 18,032 | | | 19,552 | | | | | | Income tax receivable (Note 5) | 7,514 | | | 6,792 | | Assets from risk management activities (Note 16) | 63,481 | | | 2,931 | | Deferred fuel and purchased power regulatory asset (Note 4) | 388,148 | | | 175,835 | | Other regulatory assets (Note 4) | 130,376 | | | 115,878 | | Other current assets | 83,896 | | | 76,627 | | Total current assets | 1,551,100 | | | 1,198,319 | | INVESTMENTS AND OTHER ASSETS | | | | Nuclear decommissioning trust (Notes 13 and 19) | 1,294,757 | | | 1,138,435 | | Other special use funds (Notes 13 and 19) | 358,410 | | | 254,509 | | Assets from risk management activities (Note 16) | 46,908 | | | 1,818 | | Other assets | 97,884 | | | 91,104 | | Total investments and other assets | 1,797,959 | | | 1,485,866 | | PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10) | | | | Plant in service and held for future use | 21,688,661 | | | 20,837,885 | | Accumulated depreciation and amortization | (7,504,603) | | | (7,110,310) | | Net | 14,184,058 | | | 13,727,575 | | Construction work in progress | 1,329,478 | | | 937,384 | | Palo Verde sale leaseback, net of accumulated depreciation of $256,884 and $253,014 (Note 18) | 94,166 | | | 98,036 | | Intangible assets, net of accumulated amortization of $737,694 and $698,500 | 273,693 | | | 282,570 | | Nuclear fuel, net of accumulated amortization of $133,122 and $137,207 | 106,039 | | | 113,645 | | Total property, plant and equipment | 15,987,434 | | | 15,159,210 | | DEFERRED DEBITS | | | | Regulatory assets (Notes 1, 4 and 5) | 1,192,987 | | | 1,133,987 | | Operating lease right-of-use assets (Note 9) | 890,057 | | | 505,064 | | | | | | Assets for pension and other postretirement benefits (Note 8) | 545,723 | | | 502,992 | | Other | 37,962 | | | 34,983 | | Total deferred debits | 2,666,729 | | | 2,177,026 | | TOTAL ASSETS | $ | 22,003,222 | | | $ | 20,020,421 | |
The accompanying notes are an integral part of the financial statements.
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED BALANCE SHEETS (dollars in thousands) | | | | | | | | | | | | | December 31, | | 2021 | | 2020 | LIABILITIES AND EQUITY | | | | CURRENT LIABILITIES | | | | Accounts payable | $ | 393,083 | | | $ | 318,585 | | Accrued taxes | 168,645 | | | 159,551 | | Accrued interest | 57,332 | | | 56,962 | | Common dividends payable | 95,988 | | | 93,531 | | Short-term borrowings (Note 6) | 292,000 | | | 169,000 | | Current maturities of long-term debt (Note 7) | 150,000 | | | — | | Customer deposits | 42,293 | | | 48,340 | | Liabilities from risk management activities (Note 16) | 4,373 | | | 7,557 | | Liabilities for asset retirements (Note 12) | 4,473 | | | 15,586 | | | | | | Operating lease liabilities (Note 9) | 100,443 | | | 74,785 | | Regulatory liabilities (Note 4) | 296,271 | | | 229,088 | | Other current liabilities | 151,968 | | | 187,448 | | Total current liabilities | 1,756,869 | | | 1,360,433 | | LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7) | 6,913,735 | | | 6,314,266 | | DEFERRED CREDITS AND OTHER | | | | Deferred income taxes (Note 5) | 2,311,862 | | | 2,135,403 | | Regulatory liabilities (Notes 1, 4, 5 and 8) | 2,499,213 | | | 2,450,169 | | Liabilities for asset retirements (Note 12) | 762,909 | | | 689,497 | | Liabilities for pension benefits (Note 8) | 152,865 | | | 166,484 | | Liabilities from risk management activities (Note 16) | — | | | 11,062 | | Customer advances | 257,151 | | | 221,032 | | Coal mine reclamation | 174,616 | | | 170,097 | | Deferred investment tax credit | 186,570 | | | 191,372 | | Unrecognized tax benefits (Note 5) | 4,657 | | | 5,834 | | Operating lease liabilities (Note 9) | 728,401 | | | 361,336 | | Other | 232,914 | | | 190,643 | | Total deferred credits and other | 7,311,158 | | | 6,592,929 | | COMMITMENTS AND CONTINGENCIES (SEE NOTES) | 0 | | 0 | EQUITY | | | | Common stock, no par value; authorized 150,000,000 shares, 113,014,528 and 112,760,051 issued at respective dates | 2,702,743 | | | 2,677,482 | | Treasury stock at cost; 87,608 shares at end of 2021 and 72,006 shares at end of 2020 | (6,401) | | | (6,289) | | Total common stock | 2,696,342 | | | 2,671,193 | | Retained earnings | 3,264,719 | | | 3,025,106 | | Accumulated other comprehensive loss (Note 20) | (54,861) | | | (62,796) | | Total shareholders’ equity | 5,906,200 | | | 5,633,503 | | Noncontrolling interests (Note 18) | 115,260 | | | 119,290 | | Total equity | 6,021,460 | | | 5,752,793 | | TOTAL LIABILITIES AND EQUITY | $ | 22,003,222 | | | $ | 20,020,421 | |
The accompanying notes are an integral part of the financial statements.
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands) | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | 2021 | | 2020 | | 2019 | CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | Net Income | $ | 635,944 | | | $ | 570,052 | | | $ | 557,813 | | Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | Depreciation and amortization including nuclear fuel | 719,141 | | | 686,253 | | | 664,140 | | Deferred fuel and purchased power | (256,871) | | | (93,651) | | | (82,481) | | Deferred fuel and purchased power amortization | 44,557 | | | (12,047) | | | 49,508 | | Allowance for equity funds used during construction | (41,737) | | | (33,776) | | | (31,431) | | Deferred income taxes | 117,471 | | | 69,469 | | | (1,479) | | Deferred investment tax credit | (4,802) | | | (5,096) | | | (3,938) | | | | | | | | Stock compensation | 18,460 | | | 18,292 | | | 18,376 | | Changes in current assets and liabilities: | | | | | | Customer and other receivables | (72,559) | | | (18,191) | | | (12,789) | | Accrued unbilled revenues | (1,783) | | | (4,032) | | | 9,005 | | Materials, supplies and fossil fuel | (32,870) | | | 11,623 | | | (51,826) | | Income tax receivable | (722) | | | 14,935 | | | (21,727) | | Other current assets | (22,720) | | | (30,640) | | | (3,507) | | Accounts payable | 20,267 | | | (6,059) | | | 50,641 | | Accrued taxes | 9,094 | | | 14,652 | | | (9,920) | | Other current liabilities | (52,086) | | | 22,520 | | | (84,651) | | Change in margin and collateral accounts — assets | (50) | | | 404 | | | (247) | | Change in margin and collateral accounts — liabilities | 350 | | | 100 | | | (125) | | | | | | | | Change in unrecognized tax benefits | (568) | | | 2,220 | | | 2,704 | | Change in long-term regulatory liabilities | 57,549 | | | 13,017 | | | 124,221 | | Change in other long-term assets | (246,473) | | | (67,453) | | | (82,895) | | Change in other long-term liabilities | (29,578) | | | (186,227) | | | (132,666) | | Net cash provided by operating activities | 860,014 | | | 966,365 | | | 956,726 | | CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | Capital expenditures | (1,473,475) | | | (1,326,584) | | | (1,191,447) | | Contributions in aid of construction | 105,654 | | | 62,503 | | | 70,693 | | Allowance for borrowed funds used during construction | (21,052) | | | (18,530) | | | (18,528) | | Proceeds from nuclear decommissioning trust sales and other special use funds | 1,720,966 | | | 819,518 | | | 719,034 | | Investment in nuclear decommissioning trust and other special use funds | (1,725,480) | | | (822,608) | | | (722,181) | | Other | 6,458 | | | 7,883 | | | 11,452 | | Net cash used for investing activities | (1,386,929) | | | (1,277,818) | | | (1,130,977) | | CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | Issuance of long-term debt | 746,999 | | | 1,596,672 | | | 1,092,188 | | Repayment of long-term debt | — | | | (915,150) | | | (600,000) | | Short-term borrowings and (repayments) — net | 142,000 | | | 73,325 | | | 54,275 | | Short-term debt borrowings under revolving credit facility | — | | | 751,690 | | | 49,000 | | Short-term debt repayments under revolving credit facility | (19,000) | | | (770,690) | | | (65,000) | | Dividends paid on common stock | (369,478) | | | (350,577) | | | (329,643) | | Common stock equity issuance and purchases — net | (2,350) | | | (1,389) | | | 692 | | Distributions to noncontrolling interests | (21,255) | | | (22,743) | | | (22,744) | | Net cash provided by financing activities | 476,916 | | | 361,138 | | | 178,768 | | NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (49,999) | | | 49,685 | | | 4,517 | | CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | 59,968 | | | 10,283 | | | 5,766 | | CASH AND CASH EQUIVALENTS AT END OF YEAR | $ | 9,969 | | | $ | 59,968 | | | $ | 10,283 | |
The accompanying notes are an integral part of the financial statements.
PINNACLE WEST CAPITAL CORPORATION CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (dollars in thousands, except per share amounts) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common Stock | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interests | | Total | | Shares | | Amount | | Shares | | Amount | | | | | | | | | Balance, December 31, 2018 | 112,159,896 | | | $ | 2,634,265 | | | (58,135) | | | $ | (4,825) | | | $ | 2,641,183 | | | $ | (47,708) | | | $ | 125,790 | | | $ | 5,348,705 | | | | | | | | | | | | | | | | | | Net income | | | — | | | | | — | | | 538,320 | | | — | | | 19,493 | | | 557,813 | | Other comprehensive loss | | | — | | | | | — | | | — | | | (9,388) | | | — | | | (9,388) | | Dividends on common stock ($3.04 per share) | | | — | | | | | — | | | (341,893) | | | — | | | — | | | (341,893) | | Issuance of common stock | 380,230 | | | 25,296 | | | | | — | | | — | | | — | | | — | | | 25,296 | | Purchase of treasury stock (a) | | | — | | | (121,493) | | | (11,202) | | | — | | | — | | | — | | | (11,202) | | Reissuance of treasury stock for stock-based compensation and other | | | — | | | 76,082 | | | 6,600 | | | — | | | — | | | — | | | 6,600 | | Capital activities by noncontrolling interests | | | — | | | | | — | | | — | | | — | | | (22,743) | | | (22,743) | | Balance, December 31, 2019 | 112,540,126 | | | 2,659,561 | | | (103,546) | | | (9,427) | | | 2,837,610 | | | (57,096) | | | 122,540 | | | 5,553,188 | | | | | | | | | | | | | | | | | | Net income | | | — | | | | | — | | | 550,559 | | | — | | | 19,493 | | | 570,052 | | Other comprehensive loss | | | — | | | | | — | | | — | | | (5,700) | | | — | | | (5,700) | | Dividends on common stock ($3.23 per share) | | | — | | | | | — | | | (363,063) | | | — | | | — | | | (363,063) | | Issuance of common stock | 219,925 | | | 17,921 | | | | | — | | | — | | | — | | | — | | | 17,921 | | Purchase of treasury stock (a) | | | — | | | (81,256) | | | (7,181) | | | — | | | — | | | — | | | (7,181) | | Reissuance of treasury stock for stock-based compensation and other | | | — | | | 112,796 | | | 10,319 | | | — | | | — | | | — | | | 10,319 | | Capital activities by noncontrolling interests | | | — | | | | | — | | | — | | | — | | | (22,743) | | | (22,743) | | Balance, December 31, 2020 | 112,760,051 | | | 2,677,482 | | | (72,006) | | | (6,289) | | | 3,025,106 | | | (62,796) | | | 119,290 | | | 5,752,793 | | | | | | | | | | | | | | | | | | Net income | | | — | | | | | — | | | 618,720 | | | — | | | 17,224 | | | 635,944 | | Other comprehensive income | | | — | | | | | — | | | — | | | 7,935 | | | — | | | 7,935 | | Dividends on common stock ($3.36 per share) | | | — | | | | | — | | | (379,108) | | | — | | | — | | | (379,108) | | Issuance of common stock | 254,477 | | | 25,261 | | | | | — | | | — | | | — | | | — | | | 25,261 | | Purchase of treasury stock (a) | | | — | | | (68,892) | | | (4,655) | | | — | | | — | | | — | | | (4,655) | | Reissuance of treasury stock for stock-based compensation and other | | | — | | | 53,290 | | | 4,543 | | | — | | | — | | | — | | | 4,543 | | | | | | | | | | | | | | | | | | Capital activities by noncontrolling interests | | | — | | | | | — | | | — | | | — | | | (21,255) | | | (21,255) | | Other | | | — | | | | | — | | | 1 | | | — | | | 1 | | | 2 | | Balance, December 31, 2021 | 113,014,528 | | | $ | 2,702,743 | | | (87,608) | | | $ | (6,401) | | | $ | 3,264,719 | | | $ | (54,861) | | | $ | 115,260 | | | $ | 6,021,460 | |
(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
The accompanying notes are an integral part of the financial statements.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING (ARIZONA PUBLIC SERVICE COMPANY)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2021. The effectiveness of our internal control over financial reporting as of December 31, 2021, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s financial statements. February 25, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholder and the Board of Directors of Arizona Public Service Company Phoenix, Arizona
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Arizona Public Service Company and subsidiaries (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting – Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 4 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arizona Corporation Commission (the “ACC”), which has jurisdiction with respect to the rates charged by public service utilities in Arizona. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; fuel and purchased power; operations and maintenance expense; and depreciation expense.
The ACC’s rate-making policies are premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the ACC in the future will impact the accounting for regulated operations, including decisions about the amount of allowable deferred costs
and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the ACC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment. If future recovery of regulatory assets ceases to be probable or a disallowance becomes probable, it would result in a charge to earnings.
We identified Regulatory Accounting, specifically the impact of rate regulation on the financial statements, as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory rate orders on the financial statements. 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, recent rate orders specific to APS and to other regulated entities in the same jurisdiction, and likelihood of success of legal appeals. Management judgments also include assessing the impact of potential ACC-ordered refunds to customers on regulatory liabilities. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the ACC and legal bodies, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to regulatory accounting included the following, among others: •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; 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; and the implementation of new rates as ordered by the ACC. •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. •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 precedents of the ACC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory assets and liabilities for completeness. ◦We observed the ACC open meetings for the APS 2019 Retail Rate Case. We read the ACC approved decision regarding the 2019 Retail Rate Case. ◦We obtained the Company’s internally prepared memo regarding impacts of the ACC decision to rates and recorded balances. ◦We tested that new rates were implemented within the system effective December 1, 2021.
•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 precedents set by the ACC under similar circumstances. For certain regulatory assets or liabilities where management’s assessment is based on precedents established by the ACC under similar circumstances and not specifically addressed in a regulatory order, we also obtained a letter from internal legal counsel regarding their assessment. We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment. •We evaluated management’s assessment that the SCR plant investment is not probable of a partial disallowance and that the SCR deferred costs are probable of recovery. We read the Notice of Direct Appeal filed with the Arizona Court of Appeals and Petition for Special Action filed with the Arizona Supreme Court, reviewed the Company’s internally prepared memo, and reviewed a legal letter from the Company’s external counsel to assess the likelihood of recovery in future rates or of a future reduction in rates based on the ACC decision.
/s/ Deloitte & Touche LLP
Phoenix, Arizona February 25, 2022
We have served as the Company’s auditor since 1932.
ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED STATEMENTS OF INCOME (dollars in thousands) | | | | | | | | | | Year Ended December 31, | | Year Ended December 31, | | 2021 | | 2020 | | 2019 | | 2019 | | 2018 | | 2017 | | | | | | | | | | | | | | OPERATING REVENUES (NOTE 2) | $ | 3,471,209 |
| | $ | 3,688,342 |
| | $ | 3,557,652 |
| | OPERATING REVENUES (Note 2) | | OPERATING REVENUES (Note 2) | $ | 3,803,835 | | | $ | 3,586,982 | | | $ | 3,471,209 | | | | | | | | | | | | | | OPERATING EXPENSES | |
| | |
| | |
| OPERATING EXPENSES | | | | | | Fuel and purchased power | 1,042,237 |
| | 1,094,020 |
| | 992,744 |
| Fuel and purchased power | 1,152,551 | | | 993,419 | | | 1,042,237 | | Operations and maintenance | 926,716 |
| | 969,227 |
| | 917,983 |
| Operations and maintenance | 940,588 | | | 945,181 | | | 926,716 | | Depreciation and amortization | 590,844 |
| | 580,694 |
| | 532,423 |
| Depreciation and amortization | 650,773 | | | 614,293 | | | 590,844 | | Taxes other than income taxes | 218,540 |
| | 212,136 |
| | 183,254 |
| Taxes other than income taxes | 234,569 | | | 224,790 | | | 218,540 | | Other expense | 5,888 |
| | 2,497 |
| | 6,709 |
| Other expense | 6,393 | | | 7,288 | | | 5,888 | | Total | 2,784,225 |
| | 2,858,574 |
| | 2,633,113 |
| Total | 2,984,874 | | | 2,784,971 | | | 2,784,225 | | OPERATING INCOME | 686,984 |
| | 829,768 |
| | 924,539 |
| OPERATING INCOME | 818,961 | | | 802,011 | | | 686,984 | | OTHER INCOME (DEDUCTIONS) | |
| | |
| | |
| OTHER INCOME (DEDUCTIONS) | | | | | | Allowance for equity funds used during construction (Note 1) | 31,431 |
| | 52,319 |
| | 47,011 |
| Allowance for equity funds used during construction (Note 1) | 41,737 | | | 33,776 | | | 31,431 | | Pension and other postretirement non-service credits - net (Note 8) | 24,529 |
| | 51,242 |
| | 24,371 |
| | Other income (Note 18) | 46,884 |
| | 22,746 |
| | 3,013 |
| | Other expense (Note 18) | (12,990 | ) | | (15,292 | ) | | (13,913 | ) | | Pension and other postretirement non-service credits — net (Note 8) | | Pension and other postretirement non-service credits — net (Note 8) | 112,742 | | | 57,359 | | | 24,529 | | Other income (Note 17) | | Other income (Note 17) | 43,053 | | | 51,755 | | | 46,884 | | Other expense (Note 17) | | Other expense (Note 17) | (18,897) | | | (53,694) | | | (12,990) | | Total | 89,854 |
| | 111,015 |
| | 60,482 |
| Total | 178,635 | | | 89,196 | | | 89,854 | | INTEREST EXPENSE | |
| | |
| | |
| INTEREST EXPENSE | | | | | | Interest charges | 220,174 |
| | 231,391 |
| | 214,163 |
| Interest charges | 243,592 | | | 233,452 | | | 220,174 | | Allowance for borrowed funds used during construction (Note 1) | (18,528 | ) | | (25,180 | ) | | (22,112 | ) | Allowance for borrowed funds used during construction (Note 1) | (21,052) | | | (18,530) | | | (18,528) | | Total | 201,646 |
| | 206,211 |
| | 192,051 |
| Total | 222,540 | | | 214,922 | | | 201,646 | | INCOME BEFORE INCOME TAXES | 575,192 |
| | 734,572 |
| | 792,970 |
| INCOME BEFORE INCOME TAXES | 775,056 | | | 676,285 | | | 575,192 | | INCOME TAXES (Note 5) | (9,572 | ) | | 144,814 |
| | 269,168 |
| INCOME TAXES (Note 5) | 125,553 | | | 88,764 | | | (9,572) | | NET INCOME | 584,764 |
| | 589,758 |
| | 523,802 |
| NET INCOME | 649,503 | | | 587,521 | | | 584,764 | | Less: Net income attributable to noncontrolling interests (Note 19) | 19,493 |
| | 19,493 |
| | 19,493 |
| | Less: Net income attributable to noncontrolling interests (Note 18) | | Less: Net income attributable to noncontrolling interests (Note 18) | 17,224 | | | 19,493 | | | 19,493 | | NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER | $ | 565,271 |
| | $ | 570,265 |
| | $ | 504,309 |
| NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER | $ | 632,279 | | | $ | 568,028 | | | $ | 565,271 | |
The accompanying notes are an integral part of the financial statements.
ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (dollars in thousands) | | | Year Ended December 31, | | Year Ended December 31, | | 2019 | | 2018 | | 2017 | | 2021 | | 2020 | | 2019 | | | | | | | | | | | | | NET INCOME | $ | 584,764 |
| | $ | 589,758 |
| | $ | 523,802 |
| NET INCOME | $ | 649,503 | | | $ | 587,521 | | | $ | 584,764 | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX | |
| | |
| | |
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX | | | | | | Derivative instruments: | |
| | |
| | |
| Derivative instruments: | | | | | | Net unrealized loss, net of tax benefit (expense) of $0, ($78), and $24 (Note 17) | — |
| | (78 | ) | | (35 | ) | | Reclassification of net realized loss, net of tax benefit of $375, $473, and $1,294 (Note 17) | 1,137 |
| | 1,527 |
| | 2,225 |
| | Pension and other postretirement benefits activity, net of tax benefit (expense) of $3,136, ($1,159), and $977 (Note 8) | (9,552 | ) | | 3,465 |
| | (3,750 | ) | | Net unrealized loss, net of tax expense of $18, $18, and $0 | | Net unrealized loss, net of tax expense of $18, $18, and $0 | (18) | | | (18) | | | — | | Reclassification of net realized gain, net of tax benefit (expense) of $18, $(171), and $(375) (Note 16) | | Reclassification of net realized gain, net of tax benefit (expense) of $18, $(171), and $(375) (Note 16) | 18 | | | 592 | | | 1,137 | | Pension and other postretirement benefits activity, net of tax benefit (expense) of $(1,990), $1,955, and $3,136 (Note 8) | | Pension and other postretirement benefits activity, net of tax benefit (expense) of $(1,990), $1,955, and $3,136 (Note 8) | 6,038 | | | (5,970) | | | (9,552) | | Total other comprehensive income (loss) | (8,415 | ) | | 4,914 |
| | (1,560 | ) | Total other comprehensive income (loss) | 6,038 | | | (5,396) | | | (8,415) | | | | | | | | | | | | | | COMPREHENSIVE INCOME | 576,349 |
| | 594,672 |
| | 522,242 |
| COMPREHENSIVE INCOME | 655,541 | | | 582,125 | | | 576,349 | | Less: Comprehensive income attributable to noncontrolling interests | 19,493 |
| | 19,493 |
| | 19,493 |
| Less: Comprehensive income attributable to noncontrolling interests | 17,224 | | | 19,493 | | | 19,493 | | | | | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER | $ | 556,856 |
| | $ | 575,179 |
| | $ | 502,749 |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER | $ | 638,317 | | | $ | 562,632 | | | $ | 556,856 | |
The accompanying notes are an integral part of the financial statements.
ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED BALANCE SHEETS (dollars in thousands) | | | December 31, | | December 31, | | 2019 | | 2018 | | 2021 | | 2020 | ASSETS | |
| | |
| ASSETS | | | | PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10) | |
| | |
| PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10) | | | | Plant in service and held for future use | $ | 19,832,805 |
| | $ | 18,733,142 |
| Plant in service and held for future use | $ | 21,685,200 | | | $ | 20,834,424 | | Accumulated depreciation and amortization | (6,634,597 | ) | | (6,362,771 | ) | Accumulated depreciation and amortization | (7,501,317) | | | (7,107,058) | | Net | 13,198,208 |
| | 12,370,371 |
| Net | 14,183,883 | | | 13,727,366 | | Construction work in progress | 808,133 |
| | 1,170,062 |
| Construction work in progress | 1,327,721 | | | 937,384 | | Palo Verde sale leaseback, net of accumulated depreciation of $249,144 and $245,275 (Note 19) | 101,906 |
| | 105,775 |
| | Intangible assets, net of accumulated amortization of $646,142 and $590,069 | 290,409 |
| | 262,746 |
| | Nuclear fuel, net of accumulated amortization of $137,330 and $137,850 | 123,500 |
| | 120,217 |
| | Palo Verde sale leaseback, net of accumulated depreciation of $256,884 and $253,014 (Note 18) | | Palo Verde sale leaseback, net of accumulated depreciation of $256,884 and $253,014 (Note 18) | 94,166 | | | 98,036 | | Intangible assets, net of accumulated amortization of $736,560 and $697,366 | | Intangible assets, net of accumulated amortization of $736,560 and $697,366 | 273,537 | | | 282,415 | | Nuclear fuel, net of accumulated amortization of $133,122 and $137,207 | | Nuclear fuel, net of accumulated amortization of $133,122 and $137,207 | 106,039 | | | 113,645 | | Total property, plant and equipment | 14,522,156 |
| | 14,029,171 |
| Total property, plant and equipment | 15,985,346 | | | 15,158,846 | | INVESTMENTS AND OTHER ASSETS | |
| | |
| INVESTMENTS AND OTHER ASSETS | | | | Nuclear decommissioning trust (Notes 14 and 20) | 1,010,775 |
| | 851,134 |
| | Other special use funds (Notes 14 and 20) | 245,095 |
| | 236,101 |
| | Nuclear decommissioning trust (Notes 13 and 19) | | Nuclear decommissioning trust (Notes 13 and 19) | 1,294,757 | | | 1,138,435 | | Other special use funds (Notes 13 and 19) | | Other special use funds (Notes 13 and 19) | 358,410 | | | 254,509 | | Assets from risk management activities (Note 16) | | Assets from risk management activities (Note 16) | 46,908 | | | 1,818 | | Other assets | 43,781 |
| | 40,817 |
| Other assets | 42,440 | | | 44,192 | | Total investments and other assets | 1,299,651 |
| | 1,128,052 |
| Total investments and other assets | 1,742,515 | | | 1,438,954 | | CURRENT ASSETS | |
| | |
| CURRENT ASSETS | | | | Cash and cash equivalents | 10,169 |
| | 5,707 |
| Cash and cash equivalents | 9,374 | | | 57,310 | | Customer and other receivables | 255,479 |
| | 257,654 |
| Customer and other receivables | 390,533 | | | 312,644 | | Accrued unbilled revenues | 128,165 |
| | 137,170 |
| Accrued unbilled revenues | 133,980 | | | 132,197 | | Allowance for doubtful accounts | (8,171 | ) | | (4,069 | ) | | Allowance for doubtful accounts (Note 2) | | Allowance for doubtful accounts (Note 2) | (25,354) | | | (19,782) | | Materials and supplies (at average cost) | 331,091 |
| | 269,065 |
| Materials and supplies (at average cost) | 349,135 | | | 314,745 | | Fossil fuel (at average cost) | 14,829 |
| | 25,029 |
| Fossil fuel (at average cost) | 18,032 | | | 19,552 | | Income tax receivable (Note 5) | 7,313 |
| | — |
| Income tax receivable (Note 5) | 10,756 | | | — | | Assets from risk management activities (Note 17) | 515 |
| | 1,113 |
| | Assets from risk management activities (Note 16) | | Assets from risk management activities (Note 16) | 63,481 | | | 2,931 | | Deferred fuel and purchased power regulatory asset (Note 4) | 70,137 |
| | 37,164 |
| Deferred fuel and purchased power regulatory asset (Note 4) | 388,148 | | | 175,835 | | Other regulatory assets (Note 4) | 133,070 |
| | 129,738 |
| Other regulatory assets (Note 4) | 130,376 | | | 115,878 | | | Other current assets | 38,895 |
| | 35,111 |
| Other current assets | 57,729 | | | 47,593 | | Total current assets | 981,492 |
| | 893,682 |
| Total current assets | 1,526,190 | | | 1,158,903 | | DEFERRED DEBITS | |
| | |
| DEFERRED DEBITS | | | | Regulatory assets (Notes 1, 4, and 5) | 1,304,073 |
| | 1,342,941 |
| Regulatory assets (Notes 1, 4, and 5) | 1,192,987 | | | 1,133,987 | | Operating lease right-of-use assets (Note 9) | 144,024 |
| | — |
| Operating lease right-of-use assets (Note 9) | 888,207 | | | 503,475 | | Assets for other postretirement benefits (Note 8) | 86,736 |
| | 43,212 |
| | Assets for pension and other postretirement benefits (Note 8) | | Assets for pension and other postretirement benefits (Note 8) | 537,092 | | | 495,673 | | Other | 32,591 |
| | 128,265 |
| Other | 37,319 | | | 34,413 | | Total deferred debits | 1,567,424 |
| | 1,514,418 |
| Total deferred debits | 2,655,605 | | | 2,167,548 | | TOTAL ASSETS | $ | 18,370,723 |
| | $ | 17,565,323 |
| TOTAL ASSETS | $ | 21,909,656 | | | $ | 19,924,251 | |
The accompanying notes are an integral part of the financial statements.
ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED BALANCE SHEETS (dollars in thousands) | | | December 31, | | December 31, | | 2019 | | 2018 | | 2021 | | 2020 | LIABILITIES AND EQUITY | |
| | |
| LIABILITIES AND EQUITY | | | | CAPITALIZATION | |
| | |
| CAPITALIZATION | | | | Common stock | $ | 178,162 |
| | $ | 178,162 |
| Common stock | $ | 178,162 | | | $ | 178,162 | | Additional paid-in capital | 2,721,696 |
| | 2,721,696 |
| Additional paid-in capital | 3,021,696 | | | 2,871,696 | | Retained earnings | 3,011,927 |
| | 2,788,256 |
| Retained earnings | 3,470,235 | | | 3,216,955 | | Accumulated other comprehensive loss (Note 21) | (35,522 | ) | | (27,107 | ) | | Accumulated other comprehensive loss (Note 20) | | Accumulated other comprehensive loss (Note 20) | (34,880) | | | (40,918) | | Total shareholder equity | 5,876,263 |
| | 5,661,007 |
| Total shareholder equity | 6,635,213 | | | 6,225,895 | | Noncontrolling interests (Note 19) | 122,540 |
| | 125,790 |
| | Noncontrolling interests (Note 18) | | Noncontrolling interests (Note 18) | 115,260 | | | 119,290 | | Total equity | 5,998,803 |
| | 5,786,797 |
| Total equity | 6,750,473 | | | 6,345,185 | | Long-term debt less current maturities (Note 7) | 4,833,133 |
| | 4,189,436 |
| Long-term debt less current maturities (Note 7) | 6,266,693 | | | 5,817,945 | | Total capitalization | 10,831,936 |
| | 9,976,233 |
| Total capitalization | 13,017,166 | | | 12,163,130 | | CURRENT LIABILITIES | |
| | |
| CURRENT LIABILITIES | | | | Current maturities of long-term debt (Note 7) | 350,000 |
| | 500,000 |
| | Short-term borrowings (Note 6) | | Short-term borrowings (Note 6) | 278,700 | | | — | | | Accounts payable | 338,006 |
| | 266,277 |
| Accounts payable | 389,365 | | | 311,699 | | Accrued taxes | 136,328 |
| | 176,357 |
| Accrued taxes | 152,012 | | | 148,970 | | Accrued interest | 52,619 |
| | 60,228 |
| Accrued interest | 56,622 | | | 56,322 | | Common dividends payable | 88,000 |
| | 82,700 |
| Common dividends payable | 96,000 | | | 93,500 | | Customer deposits | 64,908 |
| | 91,174 |
| Customer deposits | 42,293 | | | 48,340 | | Liabilities from risk management activities (Note 17) | 38,946 |
| | 35,506 |
| | | Liabilities from risk management activities (Note 16) | | Liabilities from risk management activities (Note 16) | 4,373 | | | 7,557 | | Liabilities for asset retirements (Note 12) | 11,025 |
| | 19,842 |
| Liabilities for asset retirements (Note 12) | 4,473 | | | 15,586 | | | Operating lease liabilities (Note 9) | 12,549 |
| | — |
| Operating lease liabilities (Note 9) | 100,199 | | | 74,695 | | Regulatory liabilities (Note 4) | 234,912 |
| | 165,876 |
| Regulatory liabilities (Note 4) | 296,271 | | | 229,088 | | Other current liabilities | 164,736 |
| | 178,137 |
| Other current liabilities | 145,286 | | | 190,420 | | Total current liabilities | 1,492,029 |
| | 1,576,097 |
| Total current liabilities | 1,565,594 | | | 1,176,177 | | DEFERRED CREDITS AND OTHER | |
| | |
| DEFERRED CREDITS AND OTHER | | | | Deferred income taxes (Note 5) | 2,033,096 |
| | 1,812,664 |
| Deferred income taxes (Note 5) | 2,331,701 | | | 2,143,673 | | Regulatory liabilities (Notes 1, 4, 5 and 8) | 2,267,835 |
| | 2,325,976 |
| Regulatory liabilities (Notes 1, 4, 5 and 8) | 2,499,213 | | | 2,450,169 | | Liabilities for asset retirements (Note 12) | 646,193 |
| | 706,703 |
| Liabilities for asset retirements (Note 12) | 762,909 | | | 689,497 | | Liabilities for pension benefits (Note 8) | 262,243 |
| | 425,404 |
| Liabilities for pension benefits (Note 8) | 138,328 | | | 148,943 | | Liabilities from risk management activities (Note 17) | 33,186 |
| | 24,531 |
| | Liabilities from risk management activities (Note 16) | | Liabilities from risk management activities (Note 16) | — | | | 11,062 | | Customer advances | 215,330 |
| | 137,153 |
| Customer advances | 257,151 | | | 221,032 | | Coal mine reclamation | 165,695 |
| | 212,785 |
| Coal mine reclamation | 174,616 | | | 170,097 | | Deferred investment tax credit | 196,468 |
| | 200,405 |
| Deferred investment tax credit | 186,570 | | | 191,372 | | Unrecognized tax benefits (Note 5) | 40,188 |
| | 41,861 |
| Unrecognized tax benefits (Note 5) | 37,423 | | | 39,410 | | Operating lease liabilities (Note 9) | 50,092 |
| | — |
| Operating lease liabilities (Note 9) | 726,572 | | | 359,653 | | Other | 136,432 |
| | 125,511 |
| Other | 212,413 | | | 160,036 | | Total deferred credits and other | 6,046,758 |
| | 6,012,993 |
| Total deferred credits and other | 7,326,896 | | | 6,584,944 | | COMMITMENTS AND CONTINGENCIES (SEE NOTES) |
|
| |
|
| COMMITMENTS AND CONTINGENCIES (SEE NOTES) | 0 | | 0 | TOTAL LIABILITIES AND EQUITY | $ | 18,370,723 |
| | $ | 17,565,323 |
| TOTAL LIABILITIES AND EQUITY | $ | 21,909,656 | | | $ | 19,924,251 | |
The accompanying notes are an integral part of the financial statements.
ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (dollars in thousands) | | | Year Ended December 31, | | Year Ended December 31, | | 2019 | | 2018 | | 2017 | | 2021 | | 2020 | | 2019 | CASH FLOWS FROM OPERATING ACTIVITIES | |
| | |
| | |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | Net income | $ | 584,764 |
| | $ | 589,758 |
| | $ | 523,802 |
| Net income | $ | 649,503 | | | $ | 587,521 | | | $ | 584,764 | | Adjustments to reconcile net income to net cash provided by operating activities: | |
| | |
| | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | Depreciation and amortization including nuclear fuel | 664,055 |
| | 649,295 |
| | 608,935 |
| Depreciation and amortization including nuclear fuel | 719,039 | | | 686,168 | | | 664,055 | | Deferred fuel and purchased power | (82,481 | ) | | (78,277 | ) | | (48,405 | ) | Deferred fuel and purchased power | (256,871) | | | (93,651) | | | (82,481) | | Deferred fuel and purchased power amortization | 49,508 |
| | 116,750 |
| | (14,767 | ) | Deferred fuel and purchased power amortization | 44,557 | | | (12,047) | | | 49,508 | | Allowance for equity funds used during construction | (31,431 | ) | | (52,319 | ) | | (47,011 | ) | Allowance for equity funds used during construction | (41,737) | | | (33,776) | | | (31,431) | | Deferred income taxes | 48,367 |
| | 59,927 |
| | 249,465 |
| Deferred income taxes | 128,852 | | | 36,462 | | | 48,367 | | Deferred investment tax credit | (3,938 | ) | | (5,170 | ) | | (4,587 | ) | Deferred investment tax credit | (4,802) | | | (5,096) | | | (3,938) | | Change in derivative instruments fair value | — |
| | — |
| | (373 | ) | | | Changes in current assets and liabilities: | |
| | |
| | |
| Changes in current assets and liabilities: | | | | | | Customer and other receivables | (12,075 | ) | | 35,406 |
| | (68,040 | ) | Customer and other receivables | (72,101) | | | (28,206) | | | (12,075) | | Accrued unbilled revenues | 9,005 |
| | (24,736 | ) | | (4,485 | ) | Accrued unbilled revenues | (1,783) | | | (4,032) | | | 9,005 | | Materials, supplies and fossil fuel | (51,826 | ) | | (6,206 | ) | | (6,503 | ) | Materials, supplies and fossil fuel | (32,870) | | | 11,623 | | | (51,826) | | Income tax receivable | (7,313 | ) | | — |
| | 11,174 |
| Income tax receivable | (10,756) | | | 7,313 | | | (7,313) | | Other current assets | (1,461 | ) | | 31,707 |
| | (6,775 | ) | Other current assets | (25,587) | | | (24,669) | | | (1,461) | | Accounts payable | 53,258 |
| | (15,608 | ) | | (26,561 | ) | Accounts payable | 23,510 | | | (4,503) | | | 53,258 | | Accrued taxes | (40,029 | ) | | 19,008 |
| | 26,773 |
| Accrued taxes | 3,042 | | | 12,642 | | | (40,029) | | Other current liabilities | (82,138 | ) | | 25,070 |
| | 27,912 |
| Other current liabilities | (61,647) | | | 29,587 | | | (82,138) | | Change in margin and collateral accounts — assets | (247 | ) | | 143 |
| | (300 | ) | Change in margin and collateral accounts — assets | (50) | | | 404 | | | (247) | | Change in margin and collateral accounts — liabilities | (125 | ) | | (2,211 | ) | | (533 | ) | Change in margin and collateral accounts — liabilities | 350 | | | 100 | | | (125) | | | Change in unrecognized tax benefits | 2,704 |
| | (1,235 | ) | | 5,891 |
| Change in unrecognized tax benefits | (568) | | | 2,220 | | | 2,704 | | Change in long-term regulatory liabilities | 124,221 |
| | (109,284 | ) | | 45,764 |
| Change in long-term regulatory liabilities | 57,549 | | | 13,017 | | | 124,221 | | Change in other long-term assets | (85,725 | ) | | 77,952 |
| | (78,540 | ) | Change in other long-term assets | (231,804) | | | (65,139) | | | (85,725) | | Change in other long-term liabilities | (129,682 | ) | | (55,169 | ) | | (31,106 | ) | Change in other long-term liabilities | (20,272) | | | (186,871) | | | (129,682) | | Net cash flow provided by operating activities | 1,007,411 |
| | 1,254,801 |
| | 1,161,730 |
| | Net cash provided by operating activities | | Net cash provided by operating activities | 865,554 | | | 929,067 | | | 1,007,411 | | CASH FLOWS FROM INVESTING ACTIVITIES | |
| | |
| | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | Capital expenditures | (1,191,447 | ) | | (1,169,061 | ) | | (1,381,930 | ) | Capital expenditures | (1,471,795) | | | (1,326,584) | | | (1,191,447) | | Contributions in aid of construction | 70,693 |
| | 27,716 |
| | 23,708 |
| Contributions in aid of construction | 105,654 | | | 62,503 | | | 70,693 | | Allowance for borrowed funds used during construction | (18,528 | ) | | (25,180 | ) | | (22,112 | ) | Allowance for borrowed funds used during construction | (21,052) | | | (18,530) | | | (18,528) | | Proceeds from nuclear decommissioning trust sales and other special use funds | 719,034 |
| | 653,033 |
| | 542,246 |
| Proceeds from nuclear decommissioning trust sales and other special use funds | 1,720,966 | | | 819,518 | | | 719,034 | | Investment in nuclear decommissioning trust and other special use funds | (722,181 | ) | | (672,165 | ) | | (544,527 | ) | Investment in nuclear decommissioning trust and other special use funds | (1,725,480) | | | (822,608) | | | (722,181) | | Other | 6,336 |
| | (1,789 | ) | | (18,538 | ) | Other | 273 | | | (554) | | | 6,336 | | Net cash flow used for investing activities | (1,136,093 | ) | | (1,187,446 | ) | | (1,401,153 | ) | | Net cash used for investing activities | | Net cash used for investing activities | (1,391,434) | | | (1,286,255) | | | (1,136,093) | | CASH FLOWS FROM FINANCING ACTIVITIES | |
| | |
| | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | Issuance of long-term debt | 1,092,188 |
| | 295,245 |
| | 549,478 |
| Issuance of long-term debt | 446,999 | | | 1,099,722 | | | 1,092,188 | | Repayment of long-term debt | (600,000 | ) | | (182,000 | ) | | — |
| Repayment of long-term debt | — | | | (465,150) | | | (600,000) | | Short-term borrowings and (repayments) — net | — |
| | — |
| | (135,500 | ) | Short-term borrowings and (repayments) — net | 278,700 | | | — | | | — | | Short-term debt borrowings under revolving credit facility | — |
| | 25,000 |
| | — |
| Short-term debt borrowings under revolving credit facility | — | | | 540,000 | | | — | | Short-term debt repayments under revolving credit facility | — |
| | (25,000 | ) | | — |
| Short-term debt repayments under revolving credit facility | — | | | (540,000) | | | — | | Dividends paid on common stock | (336,300 | ) | | (316,000 | ) | | (296,800 | ) | Dividends paid on common stock | (376,500) | | | (357,500) | | | (336,300) | | Equity infusion from Pinnacle West | — |
| | 150,000 |
| | 150,000 |
| Equity infusion from Pinnacle West | 150,000 | | | 150,000 | | | — | | Noncontrolling interests | (22,744 | ) | | (22,744 | ) | | (22,744 | ) | Noncontrolling interests | (21,255) | | | (22,743) | | | (22,744) | | Net cash flow provided by (used for) financing activities | 133,144 |
| | (75,499 | ) | | 244,434 |
| | Net cash provided by financing activities | | Net cash provided by financing activities | 477,944 | | | 404,329 | | | 133,144 | | NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 4,462 |
| | (8,144 | ) | | 5,011 |
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (47,936) | | | 47,141 | | | 4,462 | | CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | 5,707 |
| | 13,851 |
| | 8,840 |
| CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR | 57,310 | | | 10,169 | | | 5,707 | | CASH AND CASH EQUIVALENTS AT END OF YEAR | $ | 10,169 |
| | $ | 5,707 |
| | $ | 13,851 |
| CASH AND CASH EQUIVALENTS AT END OF YEAR | $ | 9,374 | | | $ | 57,310 | | | $ | 10,169 | |
The accompanying notes are an integral part of the financial statements.
ARIZONA PUBLIC SERVICE COMPANY CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (dollars in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common Stock | | Additional Paid-In Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interests | | Total | | Shares | | Amount | | | | | | | | | | | Balance, December 31, 2018 | 71,264,947 | | | $ | 178,162 | | | $ | 2,721,696 | | | $ | 2,788,256 | | | $ | (27,107) | | | $ | 125,790 | | | $ | 5,786,797 | | | | | | | | | | | | | | | | Net income | | | — | | | — | | | 565,271 | | | — | | | 19,493 | | | 584,764 | | Other comprehensive loss | | | — | | | — | | | — | | | (8,415) | | | — | | | (8,415) | | Dividends on common stock | | | — | | | — | | | (341,600) | | | — | | | — | | | (341,600) | | | | | | | | | | | | | | | | Capital activities by noncontrolling interests | | | — | | | — | | | — | | | — | | | (22,743) | | | (22,743) | | Balance, December 31, 2019 | 71,264,947 | | | 178,162 | | | 2,721,696 | | | 3,011,927 | | | (35,522) | | | 122,540 | | | 5,998,803 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Equity infusion from Pinnacle West | | | — | | | 150,000 | | | — | | | — | | | — | | | 150,000 | | Net income | | | — | | | — | | | 568,028 | | | — | | | 19,493 | | | 587,521 | | Other comprehensive loss | | | — | | | — | | | — | | | (5,396) | | | — | | | (5,396) | | Dividends on common stock | | | — | | | — | | | (363,000) | | | — | | | — | | | (363,000) | | | | | | | | | | | | | | | | Capital activities by noncontrolling interests | | | — | | | — | | | — | | | — | | | (22,743) | | | (22,743) | | Balance, December 31, 2020 | 71,264,947 | | | 178,162 | | | 2,871,696 | | | 3,216,955 | | | (40,918) | | | 119,290 | | | 6,345,185 | | | | | | | | | | | | | | | | Equity infusion from Pinnacle West | | | — | | | 150,000 | | | — | | | — | | | — | | | 150,000 | | Net income | | | — | | | — | | | 632,279 | | | — | | | 17,224 | | | 649,503 | | Other comprehensive income | | | — | | | — | | | — | | | 6,038 | | | — | | | 6,038 | | Dividends on common stock | | | — | | | — | | | (379,000) | | | — | | | — | | | (379,000) | | Capital activities by noncontrolling interests | | | — | | | — | | | — | | | — | | | (21,255) | | | (21,255) | | Other | | | — | | | — | | | 1 | | | — | | | 1 | | | 2 | | Balance, December 31, 2021 | 71,264,947 | | | $ | 178,162 | | | $ | 3,021,696 | | | $ | 3,470,235 | | | $ | (34,880) | | | $ | 115,260 | | | $ | 6,750,473 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Common Stock | | Additional Paid-In Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interests | | Total | | Shares | | Amount | | | | | | | | | | | Balance, December 31, 2016 | 71,264,947 |
| | $ | 178,162 |
| | $ | 2,421,696 |
| | $ | 2,331,245 |
| | $ | (25,423 | ) | | $ | 132,290 |
| | $ | 5,037,970 |
| | | | | | | | | | | | | | | Equity infusion from Pinnacle West | | | — |
| | 150,000 |
| | — |
| | — |
| | — |
| | 150,000 |
| Net income | | | — |
| | — |
| | 504,309 |
| | — |
| | 19,493 |
| | 523,802 |
| Other comprehensive loss | | | — |
| | — |
| | — |
| | (1,560 | ) | | — |
| | (1,560 | ) | Dividends on common stock | | | — |
| | — |
| | (301,600 | ) | | — |
| | — |
| | (301,600 | ) | Capital activities by noncontrolling interests | | | — |
| | — |
| | — |
| | — |
| | (22,743 | ) | | (22,743 | ) | Balance, December 31, 2017 | 71,264,947 |
| | 178,162 |
| | 2,571,696 |
| | 2,533,954 |
| | (26,983 | ) | | 129,040 |
| | 5,385,869 |
| | | | | | | | | | | | | | | Equity infusion from Pinnacle West | | | — |
| | 150,000 |
| | — |
| | — |
| | — |
| | 150,000 |
| Net income | | | — |
| | — |
| | 570,265 |
| | — |
| | 19,493 |
| | 589,758 |
| Other comprehensive income | | | — |
| | — |
| | — |
| | 4,914 |
| | — |
| | 4,914 |
| Dividends on common stock | | | — |
| | — |
| | (321,001 | ) | | — |
| | — |
| | (321,001 | ) | Reclassifications of income tax effects related to new tax reform (a) | | | — |
| | — |
| | 5,038 |
| | (5,038 | ) | | — |
| | — |
| Capital activities by noncontrolling interests | | | — |
| | — |
| | — |
| | — |
| | (22,743 | ) | | (22,743 | ) | Balance, December 31, 2018 | 71,264,947 |
| | 178,162 |
| | 2,721,696 |
| | 2,788,256 |
| | (27,107 | ) | | 125,790 |
| | 5,786,797 |
| | | | | | | | | | | | | | | Net income | | | — |
| | — |
| | 565,271 |
| | — |
| | 19,493 |
| | 584,764 |
| Other comprehensive loss | | | — |
| | — |
| | — |
| | (8,415 | ) | | — |
| | (8,415 | ) | Dividends on common stock | | | — |
| | — |
| | (341,600 | ) | | — |
| | — |
| | (341,600 | ) | Capital activities by noncontrolling interests | | | — |
| | — |
| | — |
| | — |
| | (22,743 | ) | | (22,743 | ) | Balance, December 31, 2019 | 71,264,947 |
| | $ | 178,162 |
| | $ | 2,721,696 |
| | $ | 3,011,927 |
| | $ | (35,522 | ) | | $ | 122,540 |
| | $ | 5,998,803 |
|
(a) In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on
items within accumulated other comprehensive income to retained earnings.
The accompanying notes are an integral part of the financial statements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
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'sCompany’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'sPaso’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 VIEsVariable Interest Entities (each a “VIE”) 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 1918 for additional information. We have determined that Pinnacle West is the primary beneficiary of a captive insurance protected cell VIE. As of December 31, 2021, the captive cell's activities are insignificant to our consolidated financial statements. 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"(“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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Accounting APS is regulated by the ACC and the 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 revenuesRevenues 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"“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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Allowance for Doubtful Accounts The allowance for doubtful accounts represents our best estimate of existing accounts receivable and accrued unbilled revenues that will ultimately be uncollectible.uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to utilityretail electric revenues. The write-off factorsfactor used to estimate uncollectible accounts areis based upon consideration of both historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success given the existing collections environment.success. See Note 2. 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.
•AFUDC.
Pinnacle West’s property, plant and equipment included in the December 31, 20192021, and 20182020 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: | 2021 | | 2020 | Generation | $ | 9,480,572 | | | $ | 9,199,012 | | Transmission | 3,402,016 | | | 3,290,477 | | Distribution | 7,520,016 | | | 7,107,007 | | General plant | 1,286,057 | | | 1,241,389 | | Plant in service and held for future use | 21,688,661 | | | 20,837,885 | | Accumulated depreciation and amortization | (7,504,603) | | | (7,110,310) | | Net | 14,184,058 | | | 13,727,575 | | Construction work in progress | 1,329,478 | | | 937,384 | | Palo Verde sale leaseback, net of accumulated depreciation | 94,166 | | | 98,036 | | Intangible assets, net of accumulated amortization | 273,693 | | | 282,570 | | Nuclear fuel, net of accumulated amortization | 106,039 | | | 113,645 | | Total property, plant and equipment | $ | 15,987,434 | | | $ | 15,159,210 | |
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.AROs. 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, 20192021, were as follows: •Fossil plantSteam generation — 1712 years; •Nuclear plant — 2225 years; •Other generation — 2119 years; •Transmission — 4037 years; •Distribution — 3433 years; and •General plant — 87 years. Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $575 million in 2021, $553 million in 2020, and $522 million in 2019, $486 million in 2018, and $453 million in 2017.2019. For the years 20172019 through 2019,2021, the depreciation rates ranged from a low of 0.18%1.37% to a high of 24.49%12.15%. The weighted-average depreciation rate was 2.87% in 2021, 2.84% in 2020, and 2.81% in 2019, 2.81% in 2018, and 2.80% in 2017.2019.
Asset Retirement Obligations
APS has asset retirement obligationsAROs for its Palo Verde nuclear facilities and certain other generation assets. The Palo Verde asset retirement obligationARO 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 obligationsAROs 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 obligationsAROs 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 obligationARO 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 6.75% for 2021, 6.72% for 2020, and 6.98% for 2019, 7.03% for 2018, and 6.68% for 2017.2019. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed, and the property is placed in service.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On June 30, 2020, FERC issued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020, through February 28, 2021. On February 23, 2021, this waiver was extended until September 30, 2021. On September 21, 2021, it was further extended until March 21, 2022. The order provides a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic. APS has adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and has left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacts the AFUDC composite rate in 2020 and 2021 but does not impact prior years. Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements.
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 1413 for additional information about fair value measurements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.natural gas. 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. See Note 1716 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.subsidiaries, in addition to a non-qualified pension plan. 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$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 for interim storage, we now accrue a receivable and an offsetting regulatory liability through the settlement period ending December of 2019.2022. 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, | | 2021 | | 2020 | | 2019 | Cash paid (received) during the period for: | | | | | | Income taxes, net of refunds | $ | 229 | | | $ | (3,019) | | | $ | 12,535 | | Interest, net of amounts capitalized | 227,584 | | | 216,951 | | | 218,664 | | Significant non-cash investing and financing activities: | | | | | | Accrued capital expenditures | $ | 167,733 | | | $ | 113,502 | | | $ | 141,297 | | Dividends declared but not paid | 95,988 | | | 93,531 | | | 87,982 | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | 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, | | 2021 | | 2020 | | 2019 | Cash paid (received) during the period for: | | | | | | Income taxes, net of refunds | $ | 19,783 | | | $ | 41,176 | | | $ | (15,042) | | Interest, net of amounts capitalized | 217,749 | | | 206,328 | | | 204,261 | | Significant non-cash investing and financing activities: | | | | | | Accrued capital expenditures | $ | 167,657 | | | $ | 113,502 | | | $ | 141,297 | | Dividends declared but not paid | 96,000 | | | 93,500 | | | 88,000 | | | | | | | |
| | | | | | | | | | | | | | 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 |
| | — |
| | — |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Intangible Assets We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS'sAPS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $80 million in 2021, $70 million in 2020, and $66 million in 2019, $68 million in 2018, and $72 million in 2017.2019. Estimated amortization expense on existing intangible assets over the next five years is $68 million in 2020, $52 million in 2021, $41$75 million in 2022, $32$63 million in 2023, and $22$44 million in 2024.2024, $33 million in 2025, and $27 million in 2026. At December 31, 2019,2021, the weighted-average remaining amortization period for intangible assets was 86 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 CanyonBCE 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 accountaccounts and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 1413 and 2019 for more information on these investments.
Leases
We determine if an agreement is a lease at contract inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To control the use of an identified asset an entity must have both a right to obtain substantially all of the benefits from the use of the asset and the right to direct the use of the asset. If we determine an agreement is a lease, and we are the lessee, we recognize a right-of-use lease asset and a lease liability at the lease commencement date. Lease liabilities are recognized based on the present value of the fixed lease payments over the lease term. To present value lease liabilities we use the implicit rate in the lease if the information is readily available, otherwise we use our incremental borrowing rate determined at lease commencement. Our incremental borrowing rate is based on the rate of interest we would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. When measuring right-of-use assets and lease liabilities we exclude variable lease payments, other than those that depend on an index or rate or are in-substance fixed payments. For short-term leases with terms of 12 months or less, we do not recognize a right-of-use lease asset or lease liability. We recognize operating lease expense using a straight-line pattern over the periods of use.
APS enters into purchased power contracts that may contain leases. This occurs when a purchased power agreement designates a specific power plant, APS obtains substantially all of the economic benefits from the use of the plant and has the right to direct the use of the plant. Purchased power lease contracts may also include energy storage facilities. Lease costs relating to purchased power lease contracts are
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
reported in fuel and purchased power on the Consolidated Statements of Income and are subject to recovery under the PSA or RES. See Note 4. We also may enter into lease agreements related to vehicles, office space, land, and other equipment. See Note 9 for information on our lease agreements.
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, 2019,2021, 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.
2. Revenue 2. Revenue
Sources of Revenue
The following table provides detail of Pinnacle West'sWest’s consolidated revenue disaggregated by revenue sources (dollars in thousands): | | | | | | | | | | | | | | | | | | | Year Ended December 31, | | Year Ended December 31, | | Year Ended December 31, | | 2021 | | 2020 | | 2019 | Retail Electric Service | | | | | | Residential | $ | 1,913,324 | | | $ | 1,929,178 | | (a) | $ | 1,761,122 | | Non-Residential | 1,586,940 | | | 1,486,098 | | | 1,509,514 | | Wholesale Energy Sales | 187,640 | | | 93,345 | | | 121,805 | | Transmission Services for Others | 99,285 | | | 65,859 | | | 62,460 | | Other Sources | 16,646 | | | 12,502 | | | 16,308 | | Total Operating Revenues | $ | 3,803,835 | | | $ | 3,586,982 | | | $ | 3,471,209 | |
| | | | | | | | | | 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 |
|
(a) Residential revenues for the year ended December 31, 2020, reflect a $24 million reduction related to the Arizona Attorney General matter. See Note 11.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Retail Electric Revenue. Pinnacle West'sWest’s retail electric revenue is generated by our wholly ownedwholly-owned regulated subsidiary APS'sAPS’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'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 1521 days of when the services are billed. See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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'customers’ energy requirements. We may also sell generation into the wholesale markets generation 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, 2021, 2020 and 2019 were $3,760 million, $3,533 million. 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, 20192021, 2020 and 2018,2019, our revenues that do not qualify as revenue from contracts with customers were $56$44 million, $54 million and $47$56 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
There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Consolidated Balance Sheets as of December 31, 20192021, and 2018.2020.
Allowance for Doubtful Accounts
On March 13, 2020, due to the COVID-19 pandemic we voluntarily suspended disconnections of customers for nonpayment. The suspension of customer disconnections was extended from March 13, 2020, through December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021, and certain customers with past due balances were placed on eight-month payment arrangements. During this time, our disconnection policies were also impacted by the Summer Disconnection Moratorium.These circumstances and the on-going COVID-19 pandemic continue to impact our allowance for doubtful accounts including our write-off factor. We continue to monitor the impacts of COVID-19, our disconnection policies, summer moratorium, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts. See Note 1 for our accounting policies on allowance for doubtful accounts. See Note 4 for additional discussion on the COVID-19 pandemic and the Summer Disconnection Moratorium.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2021 | | Year Ended December 31, 2020 | | Year Ended December 31, 2019 | Allowance for doubtful accounts, balance at beginning of period | | $ | 19,782 | | | $ | 8,171 | | | $ | 4,069 | | Bad debt expense | | 22,251 | | | 20,633 | | | 11,819 | | Actual write-offs | | (16,679) | | | (9,022) | | | (7,717) | | Allowance for doubtful accounts, balance at end of period | | $ | 25,354 | | | $ | 19,782 | | | $ | 8,171 | |
3. New Accounting Standards Standards Adopted in 2019ASU 2021-05, Leases: Certain Leases with Variable Lease Payments
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 2016,2021, a new accounting standard was issued that amends the measurementlease accounting guidance. The amended guidance will require lessors to account for certain lease transactions, that contain variable lease payments, as operating leases. The amendments are intended to eliminate the recognition of credit losses onany day-one loss associated with certain financial instruments.sales-type and direct-financing lease transactions. The newchanges do not impact lessee accounting. The 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 mustmay be adopted using either a prospective or modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard.approach. We adopted thethis standard on January 1, 20202022, using primarily the modified retrospectivea prospective approach. While theThe adoption of this guidance changed our process and methodology for determining credit losses, these changesstandard did not have a material impact on our financial statements.
4. Regulatory Matters
COVID-19 Pandemic
During 2020 and 2021, APS implemented several programs and initiatives to help our customers deal with the economic and other impacts of the COVID-19 pandemic, including but not limited to the following:
•Suspension of Disconnections; Waiver of Late Payment Fees. APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020, until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021, and customers with past due balances of $75 or greater as of that date were automatically placed on eight-month payment arrangements. APS voluntarily began waiving late payment fees of its customers on March 13, 2020 and is continuing to waive late payment fees. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic, the Summer Disconnection Moratorium (defined below) and the related write-offs of customer delinquent accounts.
•COVID-19 Emergency Relief Package. On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. APS refunded
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. Regulatory Mattersapproximately $43 million to customers. The additional $7 million over the ACC-approved amount was the result of the kWh credit being based on historic consumption, which was different than actual consumption during the refund period.
•COVID Customer Support Fund. In 2020, APS spent more than $15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”). The COVID Customer Support Fund was comprised of (i) approximately $8.8 million in funds that are not recoverable through rates, and (ii) an additional $3.6 million in bill credits for limited income customers ordered by the ACC in December 2020, of which 50%, up to a maximum of $2.5 million, was committed to be funds that are not recoverable through rates, with the remaining bill credits being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers with a delinquency of two or more months, providing a one-time credit of $100, an expanded credit of $300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $1,000, and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance. The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $250 or their delinquent balance, whichever was less. APS has distributed all funds for all COVID Customer Support Fund programs combined. Beyond the COVID Customer Support Fund, APS has also provided $2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.
•Deferral of PSA Rate Increase. In February 2021, APS delayed the annual reset of the PSA, with 50% of the PSA rate increase taking effect in April 2021 and the remaining 50% taking effect in November 2021. See below for discussion of the PSA.
2019 Retail Rate Case Filing with the Arizona Corporation Commission
On October 31, 2019, APS filed an application with the ACC foron October 31, 2019 (the “2019 Rate Case”) seeking an annual increase in annual 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"(“SCR”) project that is currentlywas the subject of a separate proceeding (see “SCRproceeding. See “Four Corners SCR Cost Recovery” below). 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 annual revenue increase in APS'sAPS’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'sAPS’s application are:were:
•a test year comprised of twelve12 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 | % |
122
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | 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; •a rate of $0.030168 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”); •authorization to defer until APS'sAPS’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; |
▪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).Plant. See “Navajo Plant” below.
On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC. The ACC Staff recommended, among other things, (i) a $89.7 million revenue increase, (ii) an average annual customer bill increase of 2.7%, (iii) a return on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the increment of fair value rate base greater than original cost, (v) the recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) the recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommended, among other things, (i) a $20.8 million revenue decrease, (ii) an average annual customer bill decrease of 0.63%, (iii) a return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) the nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) the recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.
The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application. On November 6, 2020, APS requestedfiled its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, a (i) $169 million revenue increase, (ii) average annual customer bill increase of 5.14%, (iii) return on equity of 10%, (iv) return on the increment of fair value rate base of 0.8%, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism, to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation
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facilities, of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.
The CCT plan includes the following proposed components: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, which would primarily be funded by customers. The commitment of funds that would not be recoverable through rates of $25 million were recognized in our December 31, 2020 financials. In 2021, APS committed an additional $900,000 to be paid to the Hopi Tribe related to APS’s ownership interests in the Navajo Plant, and this amount was recognized in our December 31, 2021 financials.
On December 4, 2020, the ACC Staff and intervenors filed surrebuttal testimony.The ACC Staff reduced its recommended rate increase become effective December 1, 2020. to $59.8 million, or an average annual customer bill increase of 1.82%.In RUCO’s surrebuttal, the recommended revenue decrease changed to $50.1 million, or an average annual customer bill decrease of 1.52%.The hearing concluded on March 3, 2021 and the post-hearing briefing concluded on April 30, 2021.
On August 2, 2021, the Administrative Law Judge issued a Recommended Opinion and Order in the 2019 Rate Case (the “2019 Rate Case ROO”) and issued corrections on September 10 and September 20, 2021. The 2019 Rate Case ROO recommended, among other things, (i) a $111 million decrease in annual revenue requirements, (ii) a return on equity of 9.16%, (iii) a 0.30% return on the increment of fair value rate base greater than original cost, with total fair value rate of return further adjusted to include a 0.03% reduction to return on equity resulting in an effective fair value rate of return of 4.95%, (iv) the nonrecovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project (see “Four Corners SCR Cost Recovery” below for thisadditional information), (v) the recovery of the deferral and rate base effects of the operating costs and construction of the Ocotillo modernization project, which includes a reduction in the return on the deferral, (vi) a 15% disallowance of annual amortization of Navajo Plant regulatory asset recovery, (vii) the denial of the request to defer, until APS’s next general rate case, is currently scheduledthe increase or decrease in its Arizona property taxes attributable to begintax rate changes, and (viii) a collaborative process to review and recommend revisions to APS’s adjustment mechanisms within 12 months after the date of the decision. The 2019 Rate Case ROO also recommended that the CCT plan include the following components: (i) $50 million that will be paid over 10 years to the Navajo Nation, (ii) $5 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, and (iii) $1.675 million that will be paid to the Hopi Tribe related to APS’s ownership interests in July 2020.the Navajo Plant. These amounts would be recoverable from APS’s customers through the RES adjustment mechanism. APS filed exceptions on September 13, 2021, regarding the disallowance of the SCR cost deferrals and plant investments that was recommended in the 2019 Rate Case ROO, among other issues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On October 6, 2021 and October 27, 2021, the ACC voted on various amendments to the 2019 Rate Case ROO that would result in, among other things, (i) a return on equity of 8.70%, (ii) the recovery of the deferral and rate base effects of the operating costs and construction of the Four Corners SCR project, with the exception of $215.5 million (see “Four Corners SCR Cost Recovery” below), (iii) that the CCT plan include the following components: (a) a payment of $1 million to the Hopi Tribe within 60 days of the 2019 Rate Case decision, (b) a payment of $10 million over three years to the Navajo Nation, (c) a payment of $0.5 million to the Navajo County communities within 60 days of the 2019 Rate Case decision, (d) up to $1.25 million for electrification of homes and businesses on the Hopi reservation and (e) up to $1.25 million for the electrification of homes and businesses on the Navajo Nation reservation. These payments and expenditures are attributable to the future closures of Four Corners and Cholla, along with the prior closure of the Navajo Plant and all ordered payments and expenditures would be recoverable through rates, and (iv) a change in the residential on-peak time-of-use period from 3 p.m. to 8 p.m. to 4 p.m. to 7 p.m. Monday through Friday, excluding holidays. The 2019 Rate Case ROO, as amended, results in a total annual revenue decrease for APS of $4.8 million, excluding temporary CCT payments and expenditures. On November 2, 2021, the ACC approved the 2019 Rate Case ROO, as amended. On November 24, 2021, APS filed an application for rehearing of the 2019 Rate Case with the ACC and the application was deemed denied on December 15, 2021, as the ACC did not act upon it. On December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals and a Petition for Special Action with the Arizona Supreme Court, requesting review of the disallowance of $215 million of Four Corners SCR plant investments and deferrals (see “Four Corners SCR Cost Recovery” below for additional information) and the 20 basis point penalty reduction to the return on equity. On February 8, 2022, the Arizona Supreme Court declined to accept jurisdiction on APS’s Petition for Special Action. APS cannot predict the outcome of this proceeding.
Consistent with the 2019 Rate Case decision, APS implemented the new rates effective as of December 1, 2021. On December 3, 2021, ACC Staff notified the ACC of a discrepancy between the written decision, which approved the change in time-of-use on-peak hours to 4 p.m. to 7 p.m., but did not explicitly approve the 10 months contemplated in APS’s verbal testimony to implement the new time-of-use hours. On December 16, 2021, the ACC ordered APS to complete the implementation of the time-of-use peak period by April 1, 2022. On January 12, 2022, the ACC voted to extend the deadline until September 1, 2022, to complete the implementation of the new on-peak hours for residential customers. In addition, the ACC ordered extensive compliance and reporting obligations and will be continuing to explore whether penalties or rebates would be owed to certain customers. APS cannot predict the outcome of this matter.
APS expects to file an application with the ACC for its request.next general retail rate case by mid-year 2022 but is continuing to evaluate the timing of such filing.
Information Technology ACC Investigation
On December 16, 2021, the ACC opened an investigation into various matters related to APS’s Information Technology department, including information about technology projects, costs, vendor management leadership and decision making. APS is cooperating with the investigation. The ACC Staff has been directed to report to the ACC on the investigation in April 2022. APS cannot predict the outcome of this matter.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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,RUCO, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017“2017 Settlement Agreement"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 agreement2017 Settlement 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"(“DG”) with the purpose of expanding access to rooftop solar for lowlow- and moderate incomemoderate-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 |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS▪a change in the on-peak time-of-use period from noon to 7 p.m. to 3 p.m. to 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
•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. Onmodifications and 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“2017 Rate Case Decision"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
Table of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least NaN 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.Contents
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;
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
until the conclusion ofSee “Rate Plan Comparison Tool and Investigation” below for information regarding a review and investigation pertaining to 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;
plan comparison tool offered to APS customers can switch rate plans during an open enrollment period of six months;and other related issues. 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 RES residential distributed energy requirement for 2020. On September 23, 2020, containedthe ACC approved the 2020 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2020. In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery systems. Recovery of the costs associated with the pilot will be addressed in the 2021 DSM Plan.
On July 1, 2020, APS filed its 2021 RES rules.Implementation Plan and proposed a budget of approximately $84.7 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the RES residential distributed energy requirement for 2021. In the 2021 RES Implementation Plan, APS requested $4.5 million to meet revenue requirements associated with the APS Solar Communities program to complete installations delayed as a result of the COVID-19 pandemic in 2020.On June 7, 2021, the ACC approved the 2021 RES Implementation Plan, including APS’s requested waiver of the residential distributed energy requirements for 2021.As part of the approval, the ACC approved the requested budget and authorized APS to collect $68.3 million through the Renewable Energy Adjustment Charge to support APS’s RES programs.
In June 2021, the ACC adopted a clean energy rules package which would require APS to meet certain clean energy standards and technology procurement mandates, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process. Since the adopted clean energy rules differed
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substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures were required before the rules could become effective. On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules through the rulemaking process. Instead, the ACC opened a new docket to consider all-source requests for proposals (“RFP”) requirements and the IRP process. See “Energy Modernization Plan” below for more information.
On July 1, 2021, APS filed its 2022 RES Implementation Plan and proposed a budget of approximately $93.1 million. APS filed an amended 2022 RES Implementation Plan on December 9, 2021, with a proposed budget of $100.5 million. This budget includes funding for programs to comply with the decision in the 2019 Rate Case, including the ACC authorizing spending $20 million to $30 million in capital costs for the APS Solar Communities program each year for a period of three years from the effective date of the 2019 Rate Case decision. APS’s budget proposal supports existing approved projects and commitments and requests a permanent waiver of the RES residential and non-residential distributed energy requirements for 2022. The ACC has not yet ruled on the 20202022 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"Plan”) annually for review by and approval ofby the ACC. Verified energy savings from APS'sAPS’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 (seemechanism. See below for discussion of the LFCR).LFCR.
On September 1, 2017, APS filed its 2018 DSM Plan, which proposesproposed modifications to the demand side managementDSM 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 seekssought a requested budget of $52.6 million and requestsrequested 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 requestsrequested a budget of $34.1 million and continues APS's focusfocused on DSM strategies to better meet system and customer needs, 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 requestsrequested a budget of $51.9 million and continues APS'scontinued APS’s focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addressesaddressed all components of the pending 2018 and 2019 DSM plans,
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which enablesenabled the ACC to review the 2020 DSM Plan only. On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic. The amended 2020 DSM Plan requested the same budget amount of $51.9 million. On September 23, 2020, the ACC has not yet ruled onapproved the APSamended 2020 DSM Plan.
On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for
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current DSM programs, directly to customers through a bill credit in June 2020. APS has refunded approximately $43 million to customers. The additional $7 million over the ACC-approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption during the refund period. The difference was recorded to the DSM balancing account and was included in the 2021 DSM Implementation Plan, as described below.
On December 31, 2020, APS filed its 2021 DSM Plan, which requested a budget of $63.7 million and continued APS’s focus on DSM strategies, such as peak demand reduction, load shifting, storage and electrification strategies, as well as enhanced assistance to customers impacted economically by COVID-19.On April 6, 2021, APS filed an amended 2021 DSM Plan that proposed an additional performance incentive for customers participating in the residential energy storage pilot program approved in the 2020 RES Implementation Plan.On July 13, 2021, the ACC approved the amended 2021 DSM Plan.
On April 20, 2021, APS filed a request to extend the June 1, 2021 deadline to file its 2022 DSM Plan until 120 days after the ACC has taken action on APS’s amended 2021 DSM Plan.The ACC approved the request, granting an extension until 120 days after the ACC action on the 2021 DSM Plan, or December 31, 2021, whichever is later. On December 17, 2021, APS filed its 2022 DSM Plan which requested a budget of $78.4 million and represents an increase of approximately $14 million in DSM spending above 2021.
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•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•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);
The•the PSA rate includes (a) a “Forward Component,“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,“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,“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•the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.
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The following table shows the changes in the deferred fuel and purchased power regulatory asset for 20192021 and 20182020 (dollars in thousands): | | | | | | | | | | | | | Twelve Months Ended December 31, | | 2021 | | 2020 | Beginning balance | $ | 175,835 | | | $ | 70,137 | | Deferred fuel and purchased power costs — current period | 256,871 | | | 93,651 | | Amounts refunded/(charged) to customers | (44,558) | | | 12,047 | | Ending balance | $ | 388,148 | | | $ | 175,835 | |
| | | | | | | | | | 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, iswas $0.001658 per kWh, consistingas compared to the $0.004555 per kWh for the prior year. This rate was comprised of a Forward Componentforward component of $0.000536 per kWh and a Historical Componenthistorical component of $0.001122 per kWh. This represented a $0.002897 per kWh decrease compared to 2018.
These rates went into effect as filed on February 1, 2019.
On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. That rate was $(0.000456) per kWh, andwhich consisted of a Forward Componentforward component of $(0.002086) per kWh and a Historical Componenthistorical 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 November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021.That rate was $0.003544 per kWh, which consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh.The 2021 PSA rate is a $0.004 per kWh increase compared to the 2020 PSA year, which is the maximum permitted under the Plan of Administration for the PSA.This left $215.9 million of fuel and purchased power costs above this annual cap which will be reflected in future year resets of the PSA.These rates were to be effective on February 1, 2021, but APS delayed the effectiveness of these rates until the first billing cycle of April 2021 due to concerns of the impact on customers during COVID-19.In March 2021, the ACC voted to implement the 2021 PSA rate on a staggered basis, with 50% of the PSA rate increase taking effect in April 2021 and the remaining 50% taking effect in November 2021.The PSA rate implemented on April 1, 2021 was $0.001544 per kWh, which consisted of a forward component of $(0.004444) per kWh and a historical component of $0.005988 per kWh.On November 1, 2021, the remaining increase was implemented to a PSA rate of $0.003544 per kWh, which consisted of a forward component of $(0.004444) per kWh and a historical component of $0.007988 per kWh.As part of this approval, the ACC ordered ACC Staff to conduct a fuel and purchased power procurement audit, which is currently underway, to better understand the factors that contributed to the increase in fuel costs.APS cannot predict the outcome of this audit.
On November 30, 2021, APS filed its PSA rate for the PSA year beginning February 1, 2022. That rate was $0.007544 per kWh, which consisted of a forward component of $(0.004842) per kWh and a historical component of $0.012386 per kWh. The 2022 PSA rate is a $0.004 per kWh increase compared to the 2021 PSA year, which is the maximum permitted under the Plan of Administration for the PSA. These rates went into effect as filed on February 1, 2022. At the time of the compliance filing, the amount remaining over the annual cap was approximately $365 million of fuel and purchased power costs which will be reflected in future year resets of the PSA.
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On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to 2 energy storage power purchase tolling agreements through the PSA. ThisOn December 29, 2020, the ACC Staff filed its report and recommended the storage costs be included in the PSA once the systems are in-service.On January 12, 2021, the ACC approved this application is pending withbut did not rule on the ACC.prudency.On October 28, 2021, APS filed an application requesting approval to recover costs related to 3 additional energy storage projects through the PSA once the systems are in service. On December 16, 2021, the ACC approved this application but did not rule on the prudency. APS cannot predict the outcome of this matter.
Environmental Improvement Surcharge ("EIS"(“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 1st1 each year for qualified environmental improvements made duringsince the prior calendarrate case test 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 - 14million to $14 million per year). APS’s February 1, 20202022 application requested an increase in the charge to $8.75$11.4 million, or $2.0$1.1 million over the prior-period charge, and it will become effective with the first billing cycle in effect forApril 2022 absent the 2019-2020 rate effective year.ACC taking action.
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'sAPS’s retail customers ("(“Retail Transmission Charges"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'sAPS’s rate case ("(“2012 Settlement Agreement"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'sAPS’s actual cost of service, as disclosed in APS'sAPS’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 atwith 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. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.
On March 7, 2018,17, 2020, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporateadditional transparency for excess and deficient accumulated deferred income tax ratetaxes resulting from the Tax Act, beginning inas well as for future local, state, and federal statutory tax rate changes. APS amended its 2018March 17, 2020 filing on April 28, 2020, September 29, 2021, and October 27, 2021. In January 2022, FERC approved APS’s modifications to its 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.formula.
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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'sAPS’s annual wholesale transmission ratesrevenue requirement for all users of its transmission system increased by approximately $4.9$25.8 million for the twelve-month12-month period beginning June 1, 2019, in accordance with the FERC-approved formula. Of this amount, wholesale customer rates increased by $21.1 million and retail customer rates would have increased by approximately $4.7 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved TCA balancing account, the retail revenue requirement increased by a total of $4.9 million, resulting in a decrease to residential rates and an increase to commercial rates. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.
Effective June 1, 2020, APS’s annual wholesale transmission revenue requirement for all users of its transmission system decreased by approximately $6.1 million for the 12-month period beginning June 1, 2020, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates increased by $4.8 million and retail customer rates would have decreased by approximately $10.9 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by a total of $7.4 million, resulting in reductions to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.
Effective June 1, 2021, APS’s annual wholesale transmission revenue requirement for all users of its transmission system increased by approximately $4 million for the 12-month period beginning June 1, 2021, in accordance with the FERC-approved formula. Of this net amount, wholesale customer rates decreased by approximately $3.2 million and retail customer rates would have increased by approximately $7.2 million. However, since changes in Retail Transmission Charges are reflected through the TCA after consideration of transmission recovery in retail base rates and the ACC approved balancing account, the retail revenue requirement decreased by $28.4 million, resulting in reductions to both residential and commercial rates. An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2021.
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.kWh as set forth in the 2017 Settlement Agreement. The fixed costs recoverable by the LFCR mechanism are currently 2.56 cents for lost residential and 2.68 cents non-residential kWh as set forth in the 2019 Rate Case decision. 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). On April 14, 2020, the ACC approved the 2020
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LFCR adjustment as filed, effective with the first billing cycle in May 2020. On February 15, 2021, APS filed its 2021 annual LFCR adjustment, requesting that effective May 1, 2021, the annual LFCR recovery amount be increased to $38.5 million (an $11.8 million increase from previous levels). On April 13, 2021, the ACC voted not to approve the requested $11.8 million increase to the annual LFCR adjustment, thus the previously approved rates continue to remain intact.The $11.8 million will continue to be maintained in the LFCR regulatory asset balancing account and will be included in APS’s next LFCR application filing in accordance with the compliance requirements.
As a result of the 2019 Rate Case decision, APS’s annual LFCR adjustor rate will be dependent on an annual earnings test filing, which will compare APS’s previous year’s rate of return with the related authorized rate of return. If the actual rate of return is higher than the authorized rate of return, the LFCR rate for the subsequent year is set at zero. APS determined that the changes to the LFCR mechanism as a result of the 2019 Rate Case decision did not materially impact its results of operations and financial statements for the year ended December 31, 2021.
On February 15, 2022, APS filed its 2022 annual LFCR adjustment, requesting that effective May 1, 2022, the annual LFCR recovery amount be increased to $59.1 million (a $32.5 million increase from previous levels). The ACC’s final determination of APS’s 2022 annual LFCR adjustment filing and related earnings test may materially impact the timing and amounts of future LFCR revenue recognition. See Note 2 for a discussion of alternative revenue program accounting treatment related to certain regulatory cost recovery mechanisms and see the Regulatory Assets and Liabilities table below. APS cannot predict the outcome or timing of the ACC’s consideration and final determination of thisits 2022 annual LFCR adjustment 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'sAPS’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"II”). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the finallast billing cycle ofin March 2020.
On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II until the first billing cycle in May 2020. Amounts credited to customers after the last billing cycle in March 2020 will be recorded as a part of the balancing account and will be addressed for recovery as part of the 2019 Rate Case. 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 year28.5-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
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benefit of $39.5 million to customers through December 31, 2020. It is currently anticipated that benefits relatedOn November 20, 2020, APS filed an application to continue the amortizationTEAM Phase III monthly bill credit through the earlier of depreciation related excess deferred taxes for periods beginning after December 31, 2021, or at the conclusion of the 2019 Rate Case. On December 9, 2020, will be fullythe ACC approved this request. Both the timing of the reduction in revenues refunded through the TEAM Phase III monthly bill credit and the offsetting income tax benefit are recognized based upon APS’s seasonal kWh sales pattern.
As part of the 2019 Rate Case decision, the TEAM rates were reset to zero beginning December 31, 2021 and all impacts of the Tax Act were removed from the TEAM and incorporated into the 2019APS’s base rates. The TEAM was retained to address potential changes in tax law that may be enacted prior to a decision in APS’s next rate case filing.case.
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'sAPS’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•customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS'sAPS’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•customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
Once•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-yearan 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.
APS filed its request for a fourth-year export energy price of 9.4 cents per kWh on May 1, 2020, with a requested effective date of September 1, 2020. This price reflects the 10% annual reduction discussed above. On JanuarySeptember 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing2020, the ACC approved the annual reduction of the ACC's decision regardingexport energy price but voted to delay the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scopeeffectiveness of the proceedings, and reliedreduction in export prices until October 1, 2021. In accordance with this decision, the RCP export energy price of 9.4 cents per kWh became effective on information that was not submitted as evidence, among other alleged defects. TASC filed a NoticeOctober 1, 2021.
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See "2016“2016 Retail Rate Case Filing with the Arizona Corporation Commission"Filing” 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 Former Arizona Corporation Commissioner Robert Burns
On August 25, 2016, Commissionerthen-Commissioner Robert 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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OnAfter various proceedings between September 9, 2016 APSand March 2020, at which time Burns’ appeal of a prior dismissal by the trial court was pending before the Arizona Court of Appeals, Burns’ position as an ACC commissioner ended on January 4, 2021. Nevertheless, Burns filed a motion with the ACC aCourt of Appeals arguing that the appeal was not mooted by this fact and the court should decide the matter.On March 4, 2021, the Court of Appeals found Burns’ motion to quashbe moot because 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 judgmentAppeals had issued an opinion deciding the matter 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.same day.
On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated thatIn its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear beforeMarch 4, 2021, opinion, 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 effortAppeals affirmed the trial court’s dismissal of Burns’ complaint, concluding that Burns could not overturn the ACC’s 4-1 vote refusing to enforce his subpoenas.On March 30, 2017, APSMay 15, 2021, Burns filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response topetition for review with the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the productionArizona Supreme Court asking for reversal of the information sought byCourt of Appeals opinion and 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 Commissionerstrial court’s judgment. APS 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 opposingto Burns’ petition on July 14, 2021, requesting that the second amended complaint and requested that itpetition 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. denied.The Arizona Supreme Court of Appeals granted the request forBurns' petition and 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. Onis scheduled for 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. 8, 2022.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.this matter.
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 initial Energy Modernization Plan was proposed, 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"(“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 aan initial set of draft energy rules and subsequent drafts were filed by ACC Staff in regards to the Energy Modernization PlanJuly 2019, February 2020, and workshops were held on April 29, 2019 regarding these draft rules.July 2020. On July 2, 2019,30, 2020, the ACC Staff issued a revised set offinal draft energy rules which proposeproposed 100% of retail kWh sales from clean energy resources by the end of 2050. Nuclear power was defined as a RES goal of 45%clean energy resource. The proposed rules also required 50% of retail energy served be renewable by 2035the end of 2035. A new EES was not included in the proposed rules. These rules would have required utilities to file a Clean Energy Implementation Plan and a goalEnergy Efficiency Report as part of 20%their IRP every three years beginning in 2023. In addition, these rules would have changed the IRP planning horizon from 15 years to 10 years.
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The ACC held various stakeholder meetings and workshops on ACC Staff’sdiscussed the final draft energy rules at several different meetings in July through September 20192020 and have scheduled a workshop to be held on March 10 - 11, 2020.2021. On February 19,November 13, 2020, the ACC Staffapproved a final draft energy rules package. On April 19, 2021, the Administrative Law Judge issued a revised proposed setRecommended Order and Opinion on the final energy rules. In June 2021, the ACC adopted clean energy rules based on a series of ACC amendments. The adopted rules included a final standard of 100% clean energy by 2070 and the following interim standards for carbon reduction from baseline carbon emissions level: 50% reduction by December 31, 2032; 65% reduction by December 31, 2040; 80% reduction by December 31, 2050, and 95% reduction by December 31, 2060. Since the adopted clean energy rules differed substantially from the original Recommended Order and Opinion, supplemental rulemaking procedures were required before the rules could become effective. On January 26, 2022, the ACC reversed its prior decision and declined to send the final draft energy rules that will be discussed atthrough the workshop.rulemaking process. Instead, the ACC opened a new docket to consider all-source RFP requirements and the IRP process. APS cannot predict the outcome of this matter.
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Integrated Resource Planning
ACC rules require utilities to develop fifteen-year15-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’sIRPs from April 1, 2020, to June 26, 2020. On June 26, 2020, APS filed its final IRP. On July 15, 2020, the ACC extended the schedule for final ACC review of utility IRPs to February 2021. In February 2022, the ACC acknowledged APS’s IRP. The ACC also approved certain amendments to the IRP process, including, setting an EES of 1.3% of retail sales annually (averaged over a three-year period) and a demand-side resource capacity of 35% of 2020 peak demand by 2030 and authorizing future rate base treatment of qualifying demand-side resources as proposed in future rate cases. See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.
Public Utility Regulatory Policies Act
In August 2016, APS filed an application requesting that allUnder the Public Utility Regulatory Policies Act of its contracts with1978 (“PURPA”), 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 aare provided the right to sell energy and/or capacity to the host utility. Host utilities and are required to purchase powergranted relief 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.certain regulatory burdens. On December 17, 2019, the ACC denied the application and mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona and established that the rate paid to the qualifying facilities willmust be based on the long-term avoided cost. “Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis. During calendar year 2020, APS entered into 2 18-year PPAs with qualified facilities, each for 80 MW solar facilities. In March 2021, the ACC approved these agreements.
On July 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA. The final rule went into effect on December 31, 2020.
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. 15 (“Summer Disconnection Moratorium”).During the moratorium on disconnections,Summer Disconnection Moratorium, APS could not
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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,
In June 2019, 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 issuedand ACC proposed draft amendments to the customer service disconnections rules. Stakeholders submitted initial commentsOn April 14, 2021, the ACC voted to send to the formal rulemaking process a draft amendmentsrules package governing customer disconnections that allows utilities to choose between a temperature threshold (above 95 degrees and below 32 degrees) or calendar method (June 1 – October 15) for disconnection moratoriums. On November 2, 2021, the ACC approved the final rules, and on SeptemberNovember 23, 2019. ACC stakeholder meetings2021, the rules were held in September 2019, October 2019submitted to the Arizona Office of the Attorney General for final review and January 2020 regardingapproval. Although the customer service disconnections rules. Therules are not yet final, APS intends to employ the calendar method for its disconnection moratorium. This is consistent with APS’s existing 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.processes since 2019.
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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 staffStaff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. During a July 15, 2020, ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC has scheduled a workshop for February 25-26, 2020 for further consideration and discussion of thecontinues to discuss matters related to retail electric competition, rules.including the potential for additional buy-through programs or other pilot programs. At the same time, the Arizona legislature is considering a bill that would nullify, if approved, a 20-year-old electric deregulation law that has been in place since 1998. The bill has several procedural steps in the legislative process before becoming law. 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.
On August 4, 2021, Green Mountain Energy filed an application seeking a certificate of convenience and necessity to allow it to provide competitive electric generation service in Arizona.Green Mountain Energy has requested that the ACC grant it the ability to provide competitive service in APS’s and Tucson Electric Power Company’s certificated service territories and proposes to deliver a 100% renewable energy product to residential and general service customers in those service territories. APS opposes Green Mountain Energy’s application and intends to intervene to contest it. On November 3, 2021, the ACC submitted questions to the Arizona Attorney General requesting legal opinions related to a number of issues surrounding retail electric competition and the ACC’s ability to issue competitive certificates convenience and necessity. On November 26, 2021, the Administrative Law Judge issued a procedural order indicating it would not be appropriate to set a schedule until the Attorney General has provided his insights on the applicable law.
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On October 28, 2021, an ACC Commissioner docketed a letter directing ACC Staff and interested stakeholders to design a 200-300 MW pilot program that would allow residential and small commercial customers of APS to elect a competitive electricity supplier.The letter also states that similar programs should be designed for other Arizona regulated electric utilities.APS cannot predict the outcome of these future activities.
Rate Plan Comparison Tool and Investigation
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’sAPS’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. By the middle of May 2020, APS is providingprovided 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, as applicable, and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided isdid not expected to have a material impact on APS'sAPS’s financial statements. In February 2020, APS launched a new online rate comparison tool. The ACC hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. On August 20, 2020, ACC Staff filed the outside consultant’s report on APS’s rate comparison tool. The report concluded APS’s new rate comparison tool is currently investigatingworking as intended. The report also identified a small population of additional customers that may have been affected by the error and APS has provided refunds and the $25 inconvenience payment to approximately 3,800 additional customers. These additional refunds and payment for inconvenience did not have a material impact on APS’s financial statements. On September 28, 2020, the ACC discussed this matter. report but did not take any action. APS cannot predict whether additional inquiries or actions may be taken by the ACC.
APS received a civil investigative demanddemands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section that seeks(“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers.customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS is fully cooperatingcooperated with the Attorney General’s Office in this matter. On February 22, 2021, APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement resulted in APS paying $24.75 million, approximately $24 million of which has been returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the outcome of these matters. ACC.
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
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hearing for this matter occurred in September 2018. At the hearing, APS accepted ACC Staff'sStaff’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 hasdid not issuedissue a decision on this matter. APS included the costs for the SCR project in the retail rate base in its 2019 retail rate caseRate Case filing with the ACC.
On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS cannot predictbelieves the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance. Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome or timing of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of December 31, 2021. If the 2019 Rate Case decision on this matter.to disallow $215.5 million of the SCRs is ultimately upheld, APS maywill be required to record a charge to its results of operations, ifnet of tax, of approximately $154.4 million. We cannot predict the ACC issues an unfavorable decision (see SCR deferral inoutcome of the Regulatory Assets and Liabilities table below).legal challenges nor the timing of when this matter will be resolved. See above for further discussion on the 2019 Rate Case decision.
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'sAPS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS'sAPS’s remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS'sAPS’s compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it plansplanned to retire Cholla Unit 4 by the end of 2020 and the unit ceased operation in December 2020. APS has committed to end the use of coal at its remaining Cholla units by 2025.
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
decommissioning and other retirement-related costs ($7341.8 million as of December 31, 2019)2021), 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 shortenedIn accordance with the depreciation lives of Cholla Units 1 and 3 to 2025.2019 Rate Case decision, the regulatory asset is being amortized through 2033. 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 remainceased operations in operation until December 2019 under the existing plant lease.November 2019. 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.operations. In accordance with GAAP, in the second quarter of 2017, APS'sAPS’s remaining
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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
APS has been recovering a return on and of the remaining net book value of thisits interest all or a portionin the Navajo plant in base rates over its previously estimated life through 2026. Pursuant to the 2019 Rate Case decision described above, APS will be allowed continued recovery of the book value of its remaining investment in the Navajo plant ($62.2 million as of December 31, 2021), in addition to a return on the net book value, with the exception of 15% of the annual amortization expense in rates. In addition, APS will be allowed recovery of other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset will be written off and APS's net income, cash flows, and($16.8 million as of December 31, 2021). The disallowed recovery of 15% of the annual amortization does not have a material impact on APS financial position will be negatively impacted.statements.
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Regulatory Assets and Liabilities The detail of regulatory assets is as follows (dollars in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | S | | | December 31, 2021 | | December 31, 2020 | | Amortization Through | | Current | | Non-Current | | Current | | Non-Current | Pension | (a) | | $ | — | | | $ | 509,751 | | | $ | — | | | $ | 469,953 | | Deferred fuel and purchased power (b) (c) | 2022 | | 388,148 | | | — | | | 175,835 | | | — | | Income taxes — AFUDC equity | 2051 | | 7,625 | | | 164,768 | | | 7,169 | | | 158,776 | | Ocotillo deferral (e) | 2031 | | 9,507 | | | 138,143 | | | — | | | 95,723 | | Retired power plant costs | 2033 | | 15,160 | | | 99,681 | | | 28,181 | | | 114,214 | | SCR deferral (e) (f) | 2031 | | 8,147 | | | 97,624 | | | — | | | 81,307 | | Lost fixed cost recovery (b) | 2022 | | 63,889 | | | — | | | 41,807 | | | — | | Deferred property taxes | 2027 | | 8,569 | | | 41,057 | | | 8,569 | | | 49,626 | | Deferred compensation | 2036 | | — | | | 33,997 | | | — | | | 36,195 | | Income taxes — investment tax credit basis adjustment | 2056 | | 1,129 | | | 23,639 | | | 1,113 | | | 24,291 | | Four Corners cost deferral | 2024 | | 8,077 | | | 15,998 | | | 8,077 | | | 24,075 | | Palo Verde VIEs (Note 18) | 2046 | | — | | | 21,094 | | | — | | | 21,255 | | Coal reclamation | 2026 | | 2,978 | | | 13,862 | | | 1,068 | | | 16,999 | | Loss on reacquired debt | 2038 | | 1,648 | | | 9,372 | | | 1,689 | | | 10,877 | | Mead-Phoenix transmission line — contributions in aid of construction | 2050 | | 332 | | | 9,048 | | | 332 | | | 9,380 | | Tax expense adjustor mechanism (b) | 2031 | | 656 | | | 5,845 | | | 6,226 | | | — | | TCA balancing account (b) | 2023 | | 170 | | | 3,663 | | | — | | | — | | Tax expense of Medicare subsidy | 2024 | | 1,235 | | | 2,469 | | | 1,235 | | | 3,704 | | Demand side management (b) | 2022 | | 919 | | | — | | | — | | | 7,268 | | PSA interest | 2022 | | 335 | | | — | | | 4,355 | | | — | | Deferred fuel and purchased power — mark-to-market (Note 16) | 2024 | | — | | | — | | | 3,341 | | | 9,244 | | Other | Various | | — | | | 2,976 | | | 2,716 | | | 1,100 | | Total regulatory assets (d) | | | $ | 518,524 | | | $ | 1,192,987 | | | $ | 291,713 | | | $ | 1,133,987 | |
(a)This asset represents the future recovery of pension benefit obligations and expense 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. As a result of the 2019 Rate Case Decision, the amount authorized for inclusion in rate base was determined using an averaging methodology, which resulted in a reduced return in retail rates. 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.” (e)Balance includes amounts for future regulatory consideration and amortization period determination. (f)See “Four Corners SCR Cost Recovery” discussion above.
| | | | | | | | | | | | | | | | | | | 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.” |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The detail of regulatory liabilities is as follows (dollars in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | | December 31, 2020 | | Amortization Through | | Current | | Non-Current | | Current | | Non-Current | Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a) | 2046 | | $ | 40,903 | | | $ | 971,545 | | | $ | 41,330 | | | $ | 1,012,583 | | Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a) | 2058 | | 7,239 | | | 221,877 | | | 7,240 | | | 229,147 | | Asset retirement obligations | 2057 | | — | | | 614,683 | | | — | | | 506,049 | | Other postretirement benefits | (d) | | 37,789 | | | 337,027 | | | 37,705 | | | 349,588 | | Removal costs | (c) | | 69,476 | | | 50,104 | | | 52,844 | | | 103,008 | | Deferred fuel and purchased power — mark-to-market (Note 17) | 2024 | | 60,693 | | | 46,908 | | | — | | | — | | Income taxes — change in rates | 2051 | | 2,876 | | | 64,802 | | | 2,839 | | | 66,553 | | Four Corners coal reclamation | 2038 | | 2,316 | | | 53,076 | | | 5,460 | | | 49,435 | | Spent nuclear fuel | 2027 | | 6,701 | | | 38,581 | | | 6,768 | | | 44,221 | | Income taxes — deferred investment tax credit | 2056 | | 2,264 | | | 47,337 | | | 2,231 | | | 48,648 | | Renewable energy standard (b) | 2022 | | 38,453 | | | 187 | | | 39,442 | | | 103 | | FERC transmission true up (b) | 2023 | | 21,379 | | | 12,924 | | | 6,598 | | | 3,008 | | Property tax deferral (e) | 2024 | | 4,671 | | | 15,521 | | | — | | | 13,856 | | Sundance maintenance | 2031 | | — | | | 13,797 | | | 2,989 | | | 11,508 | | Demand side management (b) | 2022 | | — | | | 5,417 | | | 10,819 | | | — | | Tax expense adjustor mechanism (b) (e) | N/A | | — | | | 4,835 | | | 7,089 | | | — | | Deferred gains on utility property | 2022 | | 1,301 | | | 551 | | | 2,423 | | | 1,544 | | TCA balancing account (b) | 2022 | | — | | | — | | | 2,902 | | | 4,672 | | Active union medical trust | N/A | | — | | | — | | | — | | | 6,057 | | Other | Various | | 210 | | | 41 | | | 409 | | | 189 | | Total regulatory liabilities | | | $ | 296,271 | | | $ | 2,499,213 | | | $ | 229,088 | | | $ | 2,450,169 | |
(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. (e)Balance includes amounts for future regulatory consideration and amortization period determination.
| | | | | | | | | | | | | | | | | | | | | | 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. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. Income Taxes 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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'sCompany’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, theThe Company has recorded $57$14 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities.liabilities as of March 31, 2020, with these non-depreciation related net excess deferred tax liabilities being fully amortized as of March 31, 2020. 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, theThe Company has recorded $62$31 million of income tax benefit related to amortization of these depreciation related liabilities.net excess deferred tax liabilities for the periods ending December 31, 2021, and December 31, 2020. 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 statementStatements of income.Income.
Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax. As a result, there is 0no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. See Note 1918 for additional details related to the Palo Verde sale leaseback VIEs.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Total unrecognized tax benefits, January 1 | $ | 45,655 | | | $ | 43,435 | | | $ | 40,731 | | | $ | 45,655 | | | $ | 43,435 | | | $ | 40,731 | | Additions for tax positions of the current year | 3,305 | | | 3,418 | | | 3,373 | | | 3,305 | | | 3,418 | | | 3,373 | | Additions for tax positions of prior years | 1,449 | | | 1,431 | | | 1,843 | | | 1,449 | | | 1,431 | | | 1,843 | | Reductions for tax positions of prior years for: | | | | | | | | | | | | Changes in judgment | (2,659) | | | (1,965) | | | (2,078) | | | (2,659) | | | (1,965) | | | (2,078) | | Settlements with taxing authorities | — | | | — | | | — | | | — | | | — | | | — | | Lapses of applicable statute of limitations | (2,664) | | | (664) | | | (434) | | | (2,664) | | | (664) | | | (434) | | Total unrecognized tax benefits, December 31 | $ | 45,086 | | | $ | 45,655 | | | $ | 43,435 | | | $ | 45,086 | | | $ | 45,655 | | | $ | 43,435 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | 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 | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Tax positions, that if recognized, would decrease our effective tax rate | $ | 26,300 | | | $ | 25,714 | | | $ | 22,813 | | | $ | 26,300 | | | $ | 25,714 | | | $ | 22,813 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | 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, 20162018, 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 2015.2017.
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 | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Unrecognized tax benefit interest expense/(benefit) recognized | $ | (535) | | | $ | 266 | | | $ | 459 | | | $ | (535) | | | $ | 266 | | | $ | 459 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pinnacle West Consolidated | | APS Consolidated | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Unrecognized tax benefit interest accrued | $ | 1,320 | | | $ | 1,855 | | | $ | 1,589 | | | $ | 1,320 | | | $ | 1,855 | | | $ | 1,589 | |
Additionally, as of December 31, 2019,2021, 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Current: | | | | | | | | | | | | Federal | $ | (5,041) | | | $ | 11,869 | | | $ | (13,551) | | | $ | 1,514 | | | $ | 57,299 | | | $ | (54,697) | | State | 2,458 | | | 1,932 | | | 3,195 | | | (11) | | | 99 | | | 695 | | Total current | (2,583) | | | 13,801 | | | (10,356) | | | 1,503 | | | 57,398 | | | (54,002) | | Deferred: | | | | | | | | | | | | Federal | 95,327 | | | 53,398 | | | (14,982) | | | 101,175 | | | 15,122 | | | 29,321 | | State | 17,342 | | | 10,974 | | | 9,565 | | | 22,875 | | | 16,244 | | | 15,109 | | Total deferred | 112,669 | | | 64,372 | | | (5,417) | | | 124,050 | | | 31,366 | | | 44,430 | | Income tax expense/(benefit) | $ | 110,086 | | | $ | 78,173 | | | $ | (15,773) | | | $ | 125,553 | | | $ | 88,764 | | | $ | (9,572) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | 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 21% 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, | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Federal income tax expense at statutory rate | $ | 156,666 | | | $ | 136,127 | | | $ | 113,828 | | | $ | 162,762 | | | $ | 142,020 | | | $ | 120,790 | | Increases (reductions) in tax expense resulting from: | | | | | | | | | | | | State income tax net of federal income tax benefit | 22,656 | | | 19,146 | | | 18,599 | | | 23,339 | | | 20,124 | | | 19,267 | | State income tax credits net of federal income tax benefit | (7,015) | | | (8,951) | | | (8,519) | | | (5,277) | | | (7,213) | | | (6,781) | | Net operating loss carryback tax benefit | (5,915) | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | Excess deferred income taxes — Tax Cuts and Jobs Act | (36,558) | | | (50,543) | | | (124,082) | | | (36,558) | | | (50,543) | | | (124,082) | | Allowance for equity funds used during construction (see Note 1) | (4,180) | | | (2,747) | | | (2,476) | | | (4,180) | | | (2,747) | | | (2,476) | | Palo Verde VIE noncontrolling interest (see Note 18) | (3,617) | | | (4,094) | | | (4,094) | | | (3,617) | | | (4,094) | | | (4,094) | | Investment tax credit amortization | (7,620) | | | (7,510) | | | (6,851) | | | (7,620) | | | (7,510) | | | (6,851) | | Other | (4,331) | | | (3,255) | | | (2,178) | | | (3,296) | | | (1,273) | | | (5,345) | | Income tax expense/(benefit) | $ | 110,086 | | | $ | 78,173 | | | $ | (15,773) | | | $ | 125,553 | | | $ | 88,764 | | | $ | (9,572) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | 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 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | Pinnacle West Consolidated | | APS Consolidated | | December 31, | | December 31, | | 2021 | | 2020 | | 2021 | | 2020 | DEFERRED TAX ASSETS | | | | | | | | Risk management activities | $ | 677 | | | $ | 4,287 | | | $ | 677 | | | $ | 4,287 | | Regulatory liabilities: | | | | | | | | Excess deferred income taxes — Tax Cuts and Jobs Act | 306,915 | | | 319,091 | | | 306,915 | | | 319,091 | | Asset retirement obligation and removal costs | 174,952 | | | 157,470 | | | 174,952 | | | 157,470 | | Unamortized investment tax credits | 49,601 | | | 50,879 | | | 49,601 | | | 50,879 | | Other postretirement benefits | 92,654 | | | 95,778 | | | 92,654 | | | 95,778 | | Other | 65,815 | | | 43,551 | | | 65,815 | | | 43,551 | | Operating lease liabilities | 204,890 | | | 107,853 | | | 204,378 | | | 107,414 | | Pension liabilities | 42,136 | | | 45,853 | | | 37,814 | | | 40,168 | | Coal reclamation liabilities | 43,165 | | | 42,065 | | | 43,165 | | | 42,065 | | Renewable energy incentives | 22,646 | | | 25,355 | | | 22,646 | | | 25,355 | | Credit and loss carryforwards | 57,077 | | | 26,460 | | | 18,902 | | | 8,034 | | Other | 74,184 | | | 78,113 | | | 74,184 | | | 78,113 | | Total deferred tax assets | 1,134,712 | | | 996,755 | | | 1,091,703 | | | 972,205 | | DEFERRED TAX LIABILITIES | | | | | | | | Plant-related | (2,570,613) | | | (2,489,899) | | | (2,570,613) | | | (2,489,899) | | Risk management activities | (27,276) | | | (1,174) | | | (27,276) | | | (1,174) | | Pension and other postretirement assets | (133,624) | | | (123,462) | | | (132,769) | | | (122,580) | | Other special use funds | (64,610) | | | (42,927) | | | (64,610) | | | (42,927) | | Operating lease right-of-use assets | (204,890) | | | (107,853) | | | (204,378) | | | (107,414) | | Regulatory assets: | | | | | | | | Allowance for equity funds used during construction | (42,616) | | | (41,038) | | | (42,616) | | | (41,038) | | Deferred fuel and purchased power | (96,033) | | | (47,673) | | | (96,033) | | | (47,673) | | Pension benefits | (126,010) | | | (116,219) | | | (126,010) | | | (116,219) | | Retired power plant costs | (28,389) | | | (35,214) | | | (28,389) | | | (35,214) | | Other | (123,902) | | | (106,227) | | | (123,902) | | | (106,227) | | Other | (28,611) | | | (20,472) | | | (6,808) | | | (5,513) | | Total deferred tax liabilities | (3,446,574) | | | (3,132,158) | | | (3,423,404) | | | (3,115,878) | | Deferred income taxes — net | $ | (2,311,862) | | | $ | (2,135,403) | | | $ | (2,331,701) | | | $ | (2,143,673) | |
As of December 31, 2019, the2021, PNW Consolidated deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately $62$51 million, which first begin to expire in 2036, state credit carryforwards net of federal benefit of $23$42 million, which first begin to expire in 2023, and otherArizona net operating loss net of federal carryforwardsbenefit of $9$6 million,. The which will expire in 2041. PNW Consolidated credit and loss carryforwards amount above has been reduced by $39$42 million of unrecognized tax benefits. As of December 31, 2021, APS Consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $24 million, which first begin to expire in 2024 and Arizona net operating loss net of federal benefit of $4 million, which will expire in 2041. APS
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidated credit and loss carryforwards amount above has been reduced by $9 million of unrecognized tax benefits.
6. Lines of Credit and Short-Term Borrowings
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.purposes.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2021 | | December 31, 2020 | | Pinnacle West | APS | Total | | Pinnacle West | APS | Total | Commitments under Credit Facilities | $ | 200,000 | | $ | 1,000,000 | | $ | 1,200,000 | | | $ | 231,000 | | $ | 1,000,000 | | $ | 1,231,000 | | Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings | (13,300) | | (278,700) | | (292,000) | | | (169,000) | | — | | (169,000) | | Amount of Credit Facilities Available | $ | 186,700 | | $ | 721,300 | | $ | 908,000 | | | $ | 62,000 | | $ | 1,000,000 | | $ | 1,062,000 | | | | | | | | | | Commitment Fees | 0.175% | 0.125% | | | 0.125% | 0.100% | |
| | | | | | | | | | | | | | | | | | | | | | 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, 2019,5, 2020, Pinnacle West entered into arefinanced its 364-day $50 million term loan agreement with a new 364-day $31 million term loan facility that matureswould have matured May 7, 2020. 4, 2021. Borrowings under the facility bore interest at Eurodollar Rate plus 1.40% per annum. Pinnacle West used the proceeds to refinance indebtedness under and terminate a prior $150repaid this facility on April 27, 2021.
On May 28, 2021, Pinnacle West replaced its $200 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 millionin outstanding borrowings under the agreement.
At December 31, 2019, Pinnacle West hadfacility that would have matured on July 11, 2023, with a new $200 million revolving credit facility that matures in July 2023.on May 28, 2026. 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'sWest’s senior unsecured debt credit ratings.ratings and the agreement includes a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. The facility is available to support Pinnacle West’s general corporate purposes, including support for Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At December 31, 2019,2021, Pinnacle West had 0no outstanding borrowings under its revolving credit facility, 0no letters of credit outstanding under the credit facility and $77$13 million of commercial paper borrowings.
APS At December 31, 2019,On May 28, 2021, APS hadreplaced its 2 $500 million revolving credit facilities totalingthat would have matured on June 29, 2022 and July 11, 2023, respectively, with 2 new $500 million revolving credit facilities that total $1 billion including a $500 million credit facilityand that matures in June 2022 and a $500 million facility that matures in July 2023.mature on May 28, 2026. 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings.ratings and the agreements include a sustainability-linked pricing metric which permits an interest rate reduction or increase by meeting or missing targets related to specific environmental and employee health and safety sustainability objectives. These facilities are available to support APS’s $500general corporate purposes, including support for APS’s $750 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2019,2021, APS had 0 commercial paperno outstanding and 0 outstanding borrowings or letters of credit under its revolving credit facilities. facilities, no letters of credit outstanding under the credit facilities and $279 million of outstanding commercial paper borrowings.
See "Financial Assurances"“Financial Assurances” in Note 11 for a discussion of APS's other outstanding letters of credit.
Debt Provisions On November 27, 2018,December 17, 2020, 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. Long-Term Debt and Liquidity Matters
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 | | 2021 | | 2020 | APS | | | | | | | | Pollution control bonds: | | | | | | | | Variable | 2029 | | (b) | | $ | 35,975 | | | $ | 35,975 | | | | | | | | | | Total pollution control bonds | | | | | 35,975 | | | 35,975 | | Senior unsecured notes | 2024-2050 | | 2.20%-6.88% | | 6,280,000 | | | 5,830,000 | | | | | | | | | | Unamortized discount | | | | | (14,995) | | | (15,900) | | Unamortized premium | | | | | 13,575 | | | 14,781 | | Unamortized debt issuance cost | | | | | (47,862) | | | (46,911) | | Total APS long-term debt | | | | | 6,266,693 | | | 5,817,945 | | Less current maturities | | | | | — | | | — | | Total APS long-term debt less current maturities | | | | | 6,266,693 | | | 5,817,945 | | Pinnacle West | | | | | | | | Senior unsecured notes | 2025 | | 1.3% | | 500,000 | | | 500,000 | | Term loans | 2022-2024 | | (c) | | 300,000 | | | — | | Unamortized discount | | | | | (34) | | | (44) | | Unamortized debt issuance cost | | | | | (2,924) | | | (3,635) | | | | | | | | | | Total Pinnacle West long-term debt | | | | | 797,042 | | | 496,321 | | Less current maturities | | | | | 150,000 | | | — | | Total Pinnacle West long-term debt less current maturities | | | | | 647,042 | | | 496,321 | | TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES | | | | | $ | 6,913,735 | | | $ | 6,314,266 | |
| | | | | | | | | | | | | | 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) | (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. |
(b) The weighted-average rate for the variable rate pollution control bonds was 0.22% at December 31, 2021, and 0.18% at December 31, 2020.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(c) The weighted-average interest rate was 0.81% at December 31, 2021. See additional details below.
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 | 2022 | | $ | 150,000 | | | $ | — | | 2023 | | — | | | — | | 2024 | | 400,000 | | | 250,000 | | 2025 | | 800,000 | | | 300,000 | | 2026 | | 250,000 | | | 250,000 | | Thereafter | | 5,515,975 | | | 5,515,975 | | Total | | $ | 7,115,975 | | | $ | 6,315,975 | |
| | | | | | | | | | 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 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2021 | | As of December 31, 2020 | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | Pinnacle West | $ | 797,042 | | | $ | 792,735 | | | $ | 496,321 | | | $ | 509,050 | | APS | 6,266,693 | | | 6,933,619 | | | 5,817,945 | | | 7,103,791 | | Total | $ | 7,063,735 | | | $ | 7,726,354 | | | $ | 6,314,266 | | | $ | 7,612,841 | |
Credit Facilities and Debt Issuances
Pinnacle West
On December 21, 2021, Pinnacle West entered into a $450 million term loan facility that matures December 20, 2024. On December 21, 2021, $150 million of the proceeds were received and recognized as long-term debt on the Consolidated Balance Sheets. On January 6, 2022, the remaining $300 million of proceeds was received and recognized on that date as long-term debt on the Consolidated Balance Sheets. The proceeds were used for general corporate purposes.
On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 30, 2022. The proceeds were received on January 4, 2021, and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 4, 2021. On January 6, 2022, Pinnacle West repaid this term loan facility early. 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, 2019,16, 2021, APS issued $300$450 million of 4.25%2.2% 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 AugustDecember 15, 2029. 2031. 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, for general corporate purposes.
$100 million of the $250 million aggregate principal amount of our 2.2% Notes due January 15, 2020.
On December 21, 2021, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On January 15, 2020, APS repaid at maturity the remaining6, 2022, Pinnacle West contributed $150 million into APS in the form of the $250 million aggregate principal amount of its 2.2% senior notes mentioned above.an equity infusion. APS used this contribution to repay short-term indebtedness.
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.
BCE
On February 11, 2022, a special purpose subsidiary of BCE entered into a credit agreement to finance capital expenditures and related costs for a microgrid project in California under development by the subsidiary. The credit facilities consist of an approximately $33 million equity bridge loan facility, an
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
approximately $42 million non-recourse construction to term loan facility, and an approximately $5 million letter of credit. In connection with the credit agreement, Pinnacle West has guaranteed the full amount of the equity bridge loan. On February 11, 2022, $12 million was drawn from the equity bridge loan. 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, 2019,2021, the ratio was approximately 52%56% for Pinnacle West and 47%50% 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"“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"“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,December 17, 2020, 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$5.9 billion to $5.9$7.5 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. 8. Retirement Plans and Other Postretirement Benefits
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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)Arrangement “HRA”) for the employees of Pinnacle West and its subsidiaries. These plans provide medical and life
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 1413 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.
Under the HRA, included in the other postretirement benefit plan, the Company provides a subsidy to retirees to defray the cost of a Medicare supplemental policy. Prior to 2020, we had been assuming a 4.75% escalation of these benefits; however, actual escalation has been significantly less than this assumption. Accordingly, during 2020 and for future periods, the escalation assumption was reduced to 2.00% (see weighted-average assumption table below). This escalation factor assumption change, among other factors, resulted in an increase in the over-funded status of the other postretirement benefit plan as of December 31, 2020. As a result, on January 4, 2021, we initiated the transfer of approximately $106 million of investment assets from the other postretirement benefit plan into the Active Union Employee Medical Account Trust. The Active Union Employee Medical Account is an existing trust account that holds investments restricted for paying active union employee medical costs. See Note 19. The transfer of other postretirement benefit plan investment assets into the Active Union Employee Medical Account permits access to approximately $106 million of assets for the sole purpose of paying active union employee medical benefits. This transfer of investment assets into the Active Union Employee Medical Account is consistent with the terms of a similar 2018 transaction.
A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore isare recoverable in rates. Accordingly, these changes are recorded as a regulatory asset or regulatory liability.Our retail rates provide for the inclusion of annual benefit costs, which allows for recovery or return of this regulatory asset/liability. See Note 4.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Plans | | Other Benefits Plans | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Service cost-benefits earned during the period | $ | 61,236 | | | $ | 56,233 | | | $ | 49,902 | | | $ | 17,796 | | | $ | 22,236 | | | $ | 18,369 | | Non-service costs (credits): | | | | | | | | | | | | Interest cost on benefit obligation | 98,566 | | | 118,567 | | | 136,843 | | | 16,513 | | | 25,857 | | | 29,894 | | Expected return on plan assets | (202,628) | | | (187,443) | | | (171,884) | | | (41,444) | | | (40,077) | | | (38,412) | | Amortization of: | | | | | | | | | | | | Prior service credit | — | | | — | | | — | | | (37,705) | | | (37,575) | | | (37,821) | | Net actuarial (gain)/loss | 15,948 | | | 34,612 | | | 42,584 | | | (10,093) | | | — | | | — | | Net periodic benefit cost/(benefit) | $ | (26,878) | | | $ | 21,969 | | | $ | 57,445 | | | $ | (54,933) | | | $ | (29,559) | | | $ | (27,970) | | Portion of cost/(benefit) charged to expense | $ | (32,743) | | | $ | 3,386 | | | $ | 30,312 | | | $ | (38,657) | | | $ | (20,966) | | | $ | (19,859) | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the plans’ changes in the benefit obligations and funded status for the years 2019 and 2018 (dollars in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | Pension Plans | | Other Benefits Plans | | 2021 | | 2020 | | 2021 | | 2020 | Change in Benefit Obligation | | | | | | | | Benefit obligation at January 1 | $ | 3,902,867 | | | $ | 3,613,114 | | | $ | 624,034 | | | $ | 746,924 | | Service cost | 61,236 | | | 56,233 | | | 17,796 | | | 22,236 | | Interest cost | 98,566 | | | 118,567 | | | 16,513 | | | 25,857 | | Benefit payments | (207,928) | | | (191,704) | | | (31,280) | | | (31,511) | | Actuarial (gain) loss | (137,917) | | | 306,657 | | | (35,222) | | | (139,472) | | Benefit obligation at December 31 | 3,716,824 | | | 3,902,867 | | | 591,841 | | | 624,034 | | Change in Plan Assets | | | | | | | | Fair value of plan assets at January 1 | 3,886,544 | | | 3,318,351 | | | 961,165 | | | 837,494 | | Actual return on plan assets | 18,169 | | | 642,373 | | | 41,432 | | | 150,076 | | Employer contributions | 100,000 | | | 100,000 | | | — | | | — | | Benefit payments | (192,672) | | | (174,180) | | | (24,310) | | | (26,405) | | Transfer to active union medical account | — | | | — | | | (105,852) | | | — | | Fair value of plan assets at December 31 | 3,812,041 | | | 3,886,544 | | | 872,435 | | | 961,165 | | Funded Status at December 31 | $ | 95,217 | | | $ | (16,323) | | | $ | 280,594 | | | $ | 337,131 | |
| | | | | | | | | | | | | | | | | | 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 obligationinformation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2019 and 2018 (dollars in thousands): | | | | | | | | | | | | | As of December 31, | | 2021 | | 2020 | Accumulated benefit obligation | 161,086 | | | 171,672 | | Fair value of plan assets | — | | | — | |
| | | | | | | | | | 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 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on an accumulated benefitsbenefit obligation basis at December 31, 2019,2021, and December 31, 2020, therefore the only pension plan with an accumulated benefitsbenefit obligation in excess of plan assets in 20192021 and 2020 is a non-qualified supplemental excess benefit retirement plan.
The following table shows information for pension plans with a projected benefit obligation in excess of plan assets (dollars in thousands): | | | | | | | | | | | | | As of December 31, | | 2021 | | 2020 | Projected benefit obligation | 169,912 | | | 182,184 | | Fair value of plan assets | — | | | — | |
The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on a projected benefit obligation basis at December 31, 2021, and December 31, 2020, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2021 and 2020 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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | Pension Plans | | Other Benefits Plans | | 2021 | | 2020 | | 2021 | | 2020 | Noncurrent asset | $ | 265,129 | | | $ | 165,861 | | | $ | 280,594 | | | $ | 337,131 | | Current liability | (17,047) | | | (15,700) | | | — | | | — | | Noncurrent liability | (152,865) | | | (166,484) | | | — | | | — | | Net amount recognized (funded status) | $ | 95,217 | | | $ | (16,323) | | | $ | 280,594 | | | $ | 337,131 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the details related to accumulated other comprehensive loss (gain) as of December 31, 20192021, and 20182020 (dollars in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | Pension Plans | | Other Benefits Plans | | 2021 | | 2020 | | 2021 | | 2020 | Net actuarial loss (gain) | $ | 582,895 | | | $ | 552,301 | | | $ | (262,352) | | | $ | (237,233) | | Prior service credit | — | | | — | | | (114,632) | | | (152,337) | | APS’s portion recorded as a regulatory (asset) liability | (509,751) | | | (469,953) | | | 374,816 | | | 387,293 | | Income tax expense (benefit) | (18,081) | | | (20,364) | | | 990 | | | 1,018 | | Accumulated other comprehensive loss (gain) | $ | 55,063 | | | $ | 61,984 | | | $ | (1,178) | | | $ | (1,259) | |
| | | | | | | | | | | | | | | | | | 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 | ) |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, | | 2021 | | 2020 | | 2021 | | 2020 | | 2019 | Discount rate – pension plans | 2.92 | % | | 2.53 | % | | 2.53 | % | | 3.30 | % | | 4.34 | % | Discount rate – other benefits plans | 2.98 | % | | 2.63 | % | | 2.63 | % | | 3.42 | % | | 4.39 | % | Rate of compensation increase | 4.00 | % | | 4.00 | % | | 4.00 | % | | 4.00 | % | | 4.00 | % | Expected long-term return on plan assets - pension plans | N/A | | N/A | | 5.30 | % | | 5.75 | % | | 6.25 | % | Expected long-term return on plan assets - other benefit plans | N/A | | N/A | | 4.90 | % | | 4.85 | % | | 5.40 | % | Initial healthcare cost trend rate (pre-65 participants) | 6.00 | % | | 6.50 | % | | 6.50 | % | | 7.00 | % | | 7.00 | % | Ultimate healthcare cost trend rate (pre-65 participants) | 4.75 | % | | 4.75 | % | | 4.75 | % | | 4.75 | % | | 4.75 | % | Number of years to ultimate trend rate (pre-65 participants) | 4 | | 5 | | 4 | | 5 | | 7 | Initial and ultimate healthcare cost trend rate (post-65 participants) (a) | 2.00 | % | | 2.00 | % | | 2.00 | % | | 4.75 | % | | 4.75 | % | | | | | | | | | | | Interest crediting rate – cash balance pension plans | 4.50 | % | | 4.50 | % | | 4.50 | % | | 4.50 | % | | 4.50 | % |
| | | | | | | | | | | | | | | | | 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 |
|
(a)See discussion above relating to this assumptions impact on benefit obligations and the January 2021 asset transfer to the Active Union Employee Medical Account.
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 2020,2022, we are assuming a 5.75%5.00% long-term rate of return for pension assets and 5.00%5.50% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 may 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'splan’s funded status at year-end 2019,2021, the target and actual allocation for the pension plan at December 31, 20192021, are as follows: | | | | | | | | | | | | | Target Allocation | | Actual Allocation | Long-term fixed income assets | 80 | % | | 79 | % | Return-generating assets | 20 | % | | 21 | % | Total | 100 | % | | 100 | % |
| | | | | | | | 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%-3% of the target allocation shown in the above table, and also considers the plan'splan’s funded status.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 | 1812 | % | Equities in emerging markets | 64 | % | Alternative investments | 144 | % | Total | 3820 | % |
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, 2019,2021, 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, 2019:2021: | | | | | | | Other BenefitsActual Allocation | | Actual Allocation | Long-term fixed income assets | 6863 | % | Return-generating assets | 3237 | % | Total | 100 | % |
See Note 1413 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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'strust’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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NAV for trusts investing in real estate is derived from the appraised values of the trust'strust’s underlying real estate assets. As of December 31, 2019,2021, 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'partnerships’ underlying assets. The plan'splan’s partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies.instruments. Certain partnerships also include funding commitments that may require the plan to contribute up to $50 million to these partnerships; as of December 31, 2019,2021, 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2019,2021, by asset category, are as follows (dollars in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | Level 1 | | Level 2 | | Other (a) | | Total | Pension Plan: | | | | | | | | Cash and cash equivalents | $ | 821 | | | $ | — | | | $ | — | | | $ | 821 | | Fixed income securities: | | | | | | | | Corporate | — | | | 1,765,623 | | | — | | | 1,765,623 | | U.S. Treasury | 1,008,211 | | | — | | | — | | | 1,008,211 | | Other (b) | — | | | 165,496 | | | — | | | 165,496 | | Common stock equities (c) | 209,063 | | | — | | | — | | | 209,063 | | Mutual funds (d) | 132,656 | | | — | | | — | | | 132,656 | | Common and collective trusts: | | | | | | | | Equities | — | | | — | | | 255,141 | | | 255,141 | | Real estate | — | | | — | | | 173,197 | | | 173,197 | | Partnerships | — | | | — | | | 15,730 | | | 15,730 | | Short-term investments and other (e) | — | | | — | | | 86,103 | | | 86,103 | | Total | $ | 1,350,751 | | | $ | 1,931,119 | | | $ | 530,171 | | | $ | 3,812,041 | | Other Benefits: | | | | | | | | Cash and cash equivalents | $ | 121 | | | $ | — | | | $ | — | | | $ | 121 | | Fixed income securities: | | | | | | | | Corporate | — | | | 244,572 | | | — | | | 244,572 | | U.S. Treasury | 287,057 | | | — | | | — | | | 287,057 | | Other (b) | — | | | 9,330 | | | — | | | 9,330 | | Common stock equities (c) | 176,024 | | | — | | | — | | | 176,024 | | Mutual funds (d) | 26,262 | | | — | | | — | | | 26,262 | | Common and collective trusts: | | | | | | | | Equities | — | | | — | | | 96,547 | | | 96,547 | | Real estate | — | | | — | | | 23,851 | | | 23,851 | | Short-term investments and other (e) | 2,517 | | | — | | | 6,154 | | | 8,671 | | Total | $ | 491,981 | | | $ | 253,902 | | | $ | 126,552 | | | $ | 872,435 | |
| | | | | | | | | | | | | | | | | | 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. |
(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 and asset backed securities. (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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2018,2020, by asset category, are as follows (dollars in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | Level 1 | | Level 2 | | Other (a) | | Total | Pension Plan: | | | | | | | | Cash and cash equivalents | $ | 9,911 | | | $ | — | | | $ | — | | | $ | 9,911 | | Fixed income securities: | | | | | | | | Corporate | — | | | 1,684,782 | | | — | | | 1,684,782 | | U.S. Treasury | 794,571 | | | — | | | — | | | 794,571 | | Other (b) | — | | | 112,224 | | | — | | | 112,224 | | Common stock equities (c) | 331,058 | | | — | | | — | | | 331,058 | | Mutual funds (d) | 262,765 | | | — | | | — | | | 262,765 | | Common and collective trusts: | | | | | | | | Equities | — | | | — | | | 407,522 | | | 407,522 | | Real estate | — | | | — | | | 191,595 | | | 191,595 | | Partnerships | — | | | — | | | 22,420 | | | 22,420 | | Short-term investments and other (e) | — | | | — | | | 69,696 | | | 69,696 | | Total | $ | 1,398,305 | | | $ | 1,797,006 | | | $ | 691,233 | | | $ | 3,886,544 | | Other Benefits: | | | | | | | | Cash and cash equivalents | $ | 1,909 | | | $ | — | | | $ | — | | | $ | 1,909 | | Fixed income securities: | | | | | | | | Corporate | — | | | 221,488 | | | — | | | 221,488 | | U.S. Treasury | 258,102 | | | — | | | — | | | 258,102 | | Other (b) | — | | | 8,316 | | | — | | | 8,316 | | Common stock equities (c) | 175,605 | | | — | | | — | | | 175,605 | | Mutual funds (d) | 34,310 | | | — | | | — | | | 34,310 | | Common and collective trusts: | | | | | | | | Equities | — | | | — | | | 94,674 | | | 94,674 | | Real estate | — | | | — | | | 19,778 | | | 19,778 | | Short-term investments and other (e) | 142,995 | | | — | | | 3,988 | | | 146,983 | | Total | $ | 612,921 | | | $ | 229,804 | | | $ | 118,440 | | | $ | 961,165 | |
| | | | | | | | | | | | | | | | | | 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.
| | (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 $100 million in 2021, $100 million in 2020, and $150 million in 2019, $50 million in 2018, and $100 million in 2017.2019. The minimum required contributions for the pension plan are 0zero for the next three years. Weyears and we do not expect to make any voluntary contributions up to $100 million per year during the 2020-2022 period.in 2022, 2023 or 2024. With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 20192021 or 2020 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.in 2022, 2023 or 2024. The Company was reimbursed
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
reimbursed$24 million in 2021, $26 million in 2020, and $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 |
|
| | | | | | | | | | | | | | | Year | | Pension Plans | | Other Benefits Plans | 2022 | | $ | 220,549 | | | $ | 31,244 | | 2023 | | 219,132 | | | 31,658 | | 2024 | | 221,724 | | | 31,486 | | 2025 | | 222,356 | | | 30,988 | | 2026 | | 221,709 | | | 30,780 | | Years 2027-2031 | | 1,121,557 | | | 151,194 | |
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 2019,2021, 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 $12 million for 2021, $11 million for 2019,2020, and $11 million for 2018, and $10 million for 2017.
9. Leases 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 20202022 through 2050. Substantially all of our leasing activities relate to APS.
In 1986, APS entered into agreements with 3 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 1918 for a discussion of VIEs.
On JanuaryMay 1, 2019 we adopted2021, APS had a new purchased power 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 leasescontract that commenced, prior to January 1, 2019. Furthermore, we electedwith a lease term expiring on October 31, 2027. On December 31, 2021, APS modified an existing purchased power lease contract that had commenced in June 2020. The lease modification extends the practical expedient transition provisions relating to the treatmentexpiration of existing land easements.this
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On January 1, 2019lease from September 30, 2025, to October 31, 2031, among other changes. These purchased power lease agreements allow APS the adoptionright to the generation capacity from certain natural-gas fueled generators during certain months of this new accounting standard resulted ineach year throughout the recognition on our Consolidated Balance Sheetsterm of approximately $194 millionthe arrangements. As APS only has rights to use the assets during certain periods of right-of-use leaseeach year the leases have non-consecutive periods of use. APS does not operate or maintain these leased assets. APS controls the dispatch of these leased assets and $119 millionis required to pay fixed monthly capacity payments during the periods of use. For these types of leased assets APS has elected to combine both the lease liabilities relating to ourand non-lease payment components and accounts for the entire fixed payment as a lease obligation. These purchased power lease contracts are accounted for as operating lease arrangements.leases. 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.contracts do not contain purchase options or term extension options. In addition to these balance sheet impacts, the adoptionfixed monthly capacity payment, APS must also pay variable charges based on the actual production volume of the guidance resultedasset. The variable consideration is not included in expandedthe measurement of our lease disclosures, which are included below.obligation.
The following table provides information related to our lease costs (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | For the Year Ended December 31, | | | 2021 | | 2020 | | 2019 | Operating Lease Cost - Purchased Power Lease Contracts | | $ | 105,762 | | | $ | 68,883 | | | 42,190 | | Operating Lease Cost - Land, Property, and Other Equipment | | 18,498 | | | 18,493 | | | 18,038 | | Total Operating Lease Cost | | 124,260 | | | 87,376 | | | 60,228 | | Variable lease cost (a) | | 118,969 | | | 122,331 | | | 114,015 | | Short-term lease cost | | 3,872 | | | 3,804 | | | 4,385 | | Total lease cost | | $ | 247,101 | | | $ | 213,511 | | | $ | 178,628 | |
| | | | | | | | | | | | | | | | 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 |
|
(a) Primarily relates to purchased power lease contracts.
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 (seeRES. See Note 4).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 fuelgeneration 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands): | | | | December 31, 2019 | | December 31, 2021 | Year | | Purchased Power Lease Contracts (a) | | Land, Property & Equipment Leases | | Total | Year | | Purchased Power Lease Contracts | | Land, Property & Equipment Leases | | Total | 2020 | | $ | — |
| | $ | 14,698 |
| | $ | 14,698 |
| | 2021 | | — |
| | 11,963 |
| | 11,963 |
| | 2022 | | — |
| | 8,331 |
| | 8,331 |
| 2022 | | $ | 103,752 | | | $ | 13,051 | | | $ | 116,803 | | 2023 | | — |
| | 6,326 |
| | 6,326 |
| 2023 | | 106,151 | | | 10,758 | | | 116,909 | | 2024 | | — |
| | 4,141 |
| | 4,141 |
| 2024 | | 104,315 | | | 8,073 | | | 112,388 | | 2025 | | 2025 | | 106,582 | | | 6,034 | | | 112,616 | | 2026 | | 2026 | | 120,016 | | | 4,803 | | | 124,819 | | Thereafter | | — |
| | 38,697 |
| | 38,697 |
| Thereafter | | 299,594 | | | 35,289 | | | 334,883 | | Total lease commitments | | — |
| | 84,156 |
| | 84,156 |
| Total lease commitments | | 840,410 | | | 78,008 | | | 918,418 | | Less imputed interest | | — |
| | 19,571 |
| | 19,571 |
| Less imputed interest | | 72,249 | | | 17,325 | | | 89,574 | | Total lease liabilities | | $ | — |
| | $ | 64,585 |
| | $ | 64,585 |
| Total lease liabilities | | $ | 768,161 | | | $ | 60,683 | | | $ | 828,844 | |
(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, 2019,2021, we have additionalvarious lease arrangements that have been executed but have not yet commenced. These arrangements primarily relate to purchased powerenergy storage assets, with expected lease contracts. These leases have commencement dates beginning inranging from June 20202022 through June 2024, with lease terms endingexpiring through October 2027.May 2044. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $705 million$1.3 billion 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 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables provide other additional information related to operating lease liabilities:liabilities (dollars in thousands): | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2021 | | Year Ended December 31, 2020 | | Year Ended December 31, 2019 | Cash paid for amounts included in the measurement of lease liabilities — operating cash flows: | $ | 116,661 | | | $ | 75,097 | | | $ | 69,075 | | Right-of-use operating lease assets obtained in exchange for operating lease liabilities | 500,582 | | | 441,653 | | | 11,262 | |
| | | | | December 31, 2019 | Weighted average remaining lease term | 13 years |
| Weighted average discount rate (a) | 3.71 | % |
| | | | | | | | | | | | | December 31, 2021 | | December 31, 2020 | Weighted average remaining lease term | 8 years | | 6 years | Weighted average discount rate (a) | 2.13 | % | | 1.69 | % |
(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 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Jointly-Owned Facilities 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, 20192021 (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Percent Owned | | | | Plant in Service | | Accumulated Depreciation | | Construction Work in Progress | Generating facilities: | | | | | | | | | | | Palo Verde Units 1 and 3 | | 29.1 | % | | | | $ | 1,932,629 | | | $ | 1,113,905 | | | $ | 28,288 | | Palo Verde Unit 2 (a) | | 16.8 | % | | | | 657,102 | | | 384,193 | | | 14,084 | | Palo Verde Common | | 28.0 | % | | (b) | | 792,849 | | | 334,804 | | | 43,690 | | Palo Verde Sale Leaseback | | | | (a) | | 351,050 | | | 256,884 | | | — | | Four Corners Generating Station | | 63.0 | % | | | | 1,686,702 | | | 608,247 | | | 21,515 | | Cholla Common Facilities (c) | | 50.5 | % | | | | 208,709 | | | 121,877 | | | 1,608 | | Transmission facilities: | | | | | | | | | | | ANPP 500kV System | | 33.5 | % | | (b) | | 133,289 | | | 53,708 | | | 115 | | Navajo Southern System | | 26.8 | % | | (b) | | 89,895 | | | 35,144 | | | 1,535 | | Palo Verde — Yuma 500kV System | | 25.8 | % | | (b) | | 23,650 | | | 7,188 | | | 716 | | Four Corners Switchyards | | 60.1 | % | | (b) | | 73,133 | | | 18,637 | | | 258 | | Phoenix — Mead System | | 17.1 | % | | (b) | | 39,523 | | | 20,150 | | | — | | Palo Verde — Rudd 500kV System | | 50.0 | % | | | | 96,376 | | | 29,426 | | | — | | Morgan — Pinnacle Peak System | | 64.7 | % | | (b) | | 119,814 | | | 23,575 | | | 138 | | Round Valley System | | 50.0 | % | | | | 535 | | | 180 | | | — | | Palo Verde — Morgan System | | 87.8 | % | | (b) | | 259,180 | | | 27,995 | | | 268 | | Hassayampa — North Gila System | | 80.0 | % | | | | 148,039 | | | 19,317 | | | — | | Cholla 500kV Switchyard | | 85.7 | % | | | | 8,287 | | | 2,163 | | | 5 | | Saguaro 500kV Switchyard | | 60.0 | % | | | | 21,655 | | | 13,471 | | | — | | Kyrene — Knox System | | 50.0 | % | | | | 578 | | | 328 | | | — | |
| | | | | | | | | | | | | | | | | | | | | | 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 18. | | (b) | Weighted-average of interests. |
| | (c) | (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.additional information), and APS operated the unit for PacifiCorp. Cholla Unit 4 was retired on December 24, 2020. The common facilities at Cholla are jointly-owned.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. Commitments and Contingencies 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"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"Contract”) for failing to accept Palo Verde'sVerde’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, stipulatingwhich required DOE to a dismissal of the lawsuit and payment by DOE topay the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007, through June 30, 2011. In addition, theThe settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019. On September 1, 2020, APS and DOE entered into an addendum to the settlement agreement allowing for the recovery of costs incurred through December 31, 2022.
APS has submitted 57 claims pursuant to the terms of the August 18, 2014, settlement agreement, for five7 separate time periods during July 1, 2011, through June 30, 2018. The2020. DOE has approved and paid $84.3$111.8 million for these claims (APS’s share is $24.5$32.5 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 (seecustomers. See Note 4).4. On October 31, 2019,November 1, 2021, APS filed its next8h claim pursuant to the terms of the August 18, 2014, settlement agreement in the amount of $16$12.2 million (APS’s share is $4.7$3.6 million). OnIn February 11, 2020,2022, the DOE approved a payment of $15.4 million (APS’s share is $4.5 million).this claim.
Nuclear Insurance Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("(“Price-Anderson Act"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$13.5 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").Insurers. The remaining balance of approximately $13.5$13.1 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 three3 Palo Verde units, APS’s maximum retrospective premium per incident for all 3 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
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insurance for a sudden and unforeseen accidental outage of any of the 3 units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited ("NEIL"(“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$22.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. In addition,Additionally, at the sole discretion of the NEIL policies contain rating triggers thatBoard of Directors, APS would resultbe liable to provide approximately $63.3 million in APS providing approximately $73.4 million of collateral assurancedeposit premium within 20 business days of a rating downgraderequest as assurance to non-investment grade.satisfy any site obligation of retrospective premium assessment. 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 20202022 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$1 billion in 2022; $616$765 million in 2023; $581$703 million in 2024; $686 million in 2025; $687 million in 2026; and $5.5$6.9 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 (seecontracts. See Note 9).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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Years Ended December 31, | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | Thereafter | Coal take-or-pay commitments (a) | $ | 202,917 | | | $ | 201,826 | | | $ | 203,638 | | | $ | 194,192 | | | $ | 195,121 | | | $ | 925,644 | | | | (a) | Total take-or-pay commitments are approximately $2.2 billion. The total net present value of these commitments is approximately $1.6 billion. |
(a)Total take-or-pay commitments are approximately $1.9 billion. The total net present value of these commitments is approximately $1.5 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): | | | | | | | | | | | | | | | | | | | Years Ended December 31, | | 2021 | | 2020 | | 2019 | Total purchases | $ | 219,958 | | | $ | 189,817 | | | $ | 204,888 | |
| | | | | | | | | | | | | | Year Ended December 31, | | 2019 | | 2018 | | 2017 | Total purchases | $ | 204,888 |
| | $ | 206,093 |
| | $ | 165,220 |
|
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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$32 million in 2022; $30 million in 2023; $28$29 million in 2024; $26 million in 2025; $22 million in 2026; and $133$87 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$175 million at December 31, 20192021, and $213$170 million at December 31, 2018.2020. 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; $20 million in 2025; $21 million in 2026; and $88$48 million thereafter. These funds are held in an escrow account and will be distributed to certain coal providers under the terms of the applicable coal supply agreements. Any amendments to current coal supply agreements may change the timing of the contribution. Portionscontribution or cost of these funds will be held in anfinal reclamation. The annual payments to the escrow account and distributedfinal distribution to certain coal providers under the terms of the applicable coal supply agreements.may be subject to adjustments based on escrow earnings.
Superfund-Related Matters The Comprehensive Environmental Response Compensation and Liability Act ("CERCLA"(“Superfund” or "Superfund"“CERCLA”) 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”). 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 52nd Street Superfund Site, Operable Unit 3 ("OU3"(“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"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 induring the springfirst or summersecond quarter of 2020. We estimate that our2022.APS's estimated costs related to this investigation and study will beis approximately $2$3 million. We anticipateAPS anticipates 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, the Roosevelt Irrigation District ("RID"(“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
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state governmental investigation into groundwater contamination in this area, on January 25, 2015, the 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, 2 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'sAPS’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'sRID’s CERCLA claims concerning both past and future cost recovery. APS'sAPS’s share of this settlement was immaterial. In addition, the 2 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.
Arizona Attorney General Matter
APS received civil investigative demands from the Attorney General seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021, APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement resulted in APS paying $24.75 million, approximately $24 million of which was returned to customers as restitution.
Four Corners SCR Cost Recovery
As part of APS’s 2019 Rate Case, APS included recovery of the deferral and rate base effects of the Four Corners SCR project. On November 2, 2021, the 2019 Rate Case decision was approved by the ACC allowing approximately $194 million of SCR related plant investments and cost deferrals in rate base and to recover, depreciate and amortize in rates based on an end-of-life assumption of July 2031. The decision also included a partial and combined disallowance of $215.5 million on the SCR investments and deferrals. APS believes the SCR plant investments and related SCR cost deferrals were prudently incurred, and on December 17, 2021, APS filed its Notice of Direct Appeal at the Arizona Court of Appeals requesting review of the $215.5 million disallowance. Based on the partial recovery of these investments and cost deferrals in current rates and the uncertainty of the outcome of the legal appeals process, APS has not recorded an impairment or write-off relating to the SCR plant investments or deferrals as of December 31, 2021. If the 2019 Rate Case decision to disallow $215.5 million of the SCRs is ultimately upheld, APS will be required to record a charge to its results of operations, net of tax, of approximately
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$154.4 million. We cannot predict the outcome of the legal challenges nor the timing of when this matter will be resolved. See Note 4 for additional information regarding the Four Corners SCR cost recovery. 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,GHGs, 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'sAPS’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'sPaso’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“Four Corners -— 4CA Matter"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 In addition, EPA issued a final rule establishing controls constituting BART for Regional Haze compliance at Cholla which would requirethat does not involve the installation of SCRnew pollution controls was unsupported and that EPA had no basiswill replace an earlier BART determination 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"this facility. 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"(“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"“forced closure” or "closure“closure for cause"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,July 29, 2020, EPA proposed that alltook final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments regardlessby April 11, 2021, at the latest.All APS disposal units subject to these closure requirements were closed as 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).April 11, 2021.
•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 July 29, 2020, final regulation adopted this proposal regardingand now requires explicit EPA approval for facilities to utilize an alternative closure deadline. With respect to the Cholla facility, APS’s application for alternative closure (which would require expressallow the continued disposal of CCR within the facility’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025) was submitted to EPA authorization for such facilitieson November 30, 2020, and is currently pending. This application will be subject to continue operating theirpublic comment and, potentially, judicial review. On January 11, 2022, EPA began issuing proposed decisions pursuant to this provision of the federal CCR disposal units under alternative closure.regulations and we anticipate receiving a proposed decision with respect to the Cholla facility in 2022.
We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action. action on those matters that are still pending.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$30 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $15$16 million. The Navajo Plant currently disposesdisposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS'sAPS’s share of incremental costs iswas 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
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Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must ceasehave ceased operating and initiateinitiated closure by October 31, 2020.April 11, 2021, at the latest (except for those disposal units subject to alternative closure). APS initiated an assessmentcompleted the assessments of corrective measures on JanuaryJune 14, 20192019; however, additional investigations and expects such assessmentengineering analyses that will continue through mid- to late-2020. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as tosupport the CCR disposal units at Cholla and Four Corners undergoing corrective action.remedy selection are still underway. In addition, APS will also solicit input from the public and 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'sEPA’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 regulationssuch rules would have had been stayed pending judicial review.
Thefar broader impact on the electric power sector than the ACE regulations. On January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations are based upon measures that can be implementedand remanded them back to improve the heat rate of steam-electricEPA to develop new existing power plants, specifically coal-fired EGUs. In contrastplant carbon regulations consistent 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 applicationcourt’s ruling. That ruling endorsed an expansive view of the ACE rule’s heat-rate improvement emission guidelines. While corresponding New Source Review (“NSR”) reform regulations were proposed as part offederal Clean Air Act consistent with EPA’s initial ACE proposal,2015 CPP. Nonetheless, on October 29, 2021, the finalized ACE regulations did not include such reform measures. EPAU.S. Supreme Court announced that it will be taking final action on EPA's NSR reform proposal for EGUswas accepting judicial review of the January D.C. Circuit decision vacating the ACE regulations. While the Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the near future.
WeClean Air Act, we cannot at this time predict the outcome of EPA's regulatory actions repealing and replacingpending EPA rulemaking proceedings or ongoing litigation related to 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 legalityscope of EPA’s action, both in repealingauthority under the CPP and issuing the ACE regulations. In addition,Clean Air Act 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.regulate carbon emissions from existing power plants.
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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"(“NPDES”) Permit
On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ("EAB") concerning theThe latest NPDES wastewater discharge permit for Four Corners which was reissuedissued on June 12, 2018. TheSeptember 30, 2019.Based upon a November 1, 2019, filing by several 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, EPAEnvironmental Appeals Board (“EAB”) took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawalup review 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. Four Corners NPDES Permit.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, basedBased upon a November 1, 2019, filing by several environmental groups. Wegroups, the EAB again took up review of the Four Corners NPDES Permit.Oral argument on this appeal
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was held on September 3, 2020, and the EAB denied the environmental group petition on September 30, 2020.On January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S. Court of Appeals for the Ninth Circuit. The September 2019 permit remains in effect pending this appeal.As of November 11, 2021, the parties to this lawsuit, including APS, reached a tentative agreement to settle this matter.Review of this agreement, including public commenting, is currently pending with EPA. Notwithstanding this tentative agreement, we cannot predict the outcome of this reviewthese appeal proceedings, including further settlement discussions, and, if settlement efforts fail and the appeal is eventually successful, whether the reviewthat outcome 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 thepurchased this 7% interest oand ultimately purchased the interest onn July 3, 2018, from 4CA. 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. The note is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement. As of December 31, 2021, the note has a remaining balance of approximately $9.2 million. NTEC continues to make payments in accordance with the terms of the note. Due to its short-remaining term, among other factors, there are no expected credit losses associated with the 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'sNTEC’s 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West'sWest’s guarantee is secured by a portion of APS'sAPS’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. These instruments support commodity contract collateral obligations and other transactions. As of December 31, 2019,2021, standby letters of credit totaled $1.7approximately $5 million and will expire in 2020.2022. As of December 31, 2019,2021, surety bonds expiring through 20202023 totaled approximately $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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2019.2021. In connection with the sale of 4CA's4CA’s 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. (See "FourSee “Four Corners -— 4CA Matter"Matter” above for information related to this guarantee.) Pinnacle West has not needed to perform under 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, including expected credit losses, to be immaterial.
In connection with BCE’s acquisition of minority ownership positions in the Clear Creek wind farm in Missouri and Nobles 2 wind farms,farm in Minnesota, 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West reduceare reduced as payments are made under the respective guaranteedguarantee agreements. The Equity Contribution Guarantees are currently anticipated to be terminated upon completionremaining as of construction of the respective projects, which is anticipated to occur prior to December 31, 2020,2021, are immaterial in amount (approximately $2 million) and the PTC Guarantees (approximately $40$37 million as of December 31, 2019)2021) are currently expected to be terminated ten10 years following the commercial operation date of the applicable project.
In connection with the credit agreement entered into by a special purpose subsidiary of BCE on February 11, 2022, Pinnacle West has guaranteed the full amount of the equity bridge loan under the credit facility. See Note 7 for additional details. 12. Asset Retirement Obligations In 2019,2021, APS receivedrevised its cost estimates for existing AROs at Cholla related to 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 millionponds 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,facilities, which resulted in an increase to the ARO of approximately $28 million. See additional details in Notes 4 and 11.
In 2020, APS revised its cost estimates for existing AROs at Cholla relating to updated estimates for the amountclosure of $14 million. In addition, dueponds and facilities, and at Four Corners and the Navajo Plant relating to the sale of 4CA assets to NTECcorrective action and water monitoring costs, which resulted in 2018 (see Note 11 for more information on 4CA matters) there was a decreasean increase to the ARO of $9$6 million. APS recognizedAlso in 2020, an updated Four Corners decommissioning study was finalized for the updated closure date of 2031, which resulted in an increase to the 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$13 million.
The following table shows the change in our asset retirement obligations for 2019 and 2018AROs (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 |
|
| | | | | | | | | | | | | 2021 | | 2020 | Asset retirement obligations at the beginning of year | $ | 705,083 | | | $ | 657,218 | | Changes attributable to: | | | | Accretion expense | 38,437 | | | 38,652 | | Settlements | (4,111) | | | (9,710) | | | | | | Estimated cash flow revisions | 27,973 | | | 18,923 | | Asset retirement obligations at the end of year | $ | 767,382 | | | $ | 705,083 | |
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. Selected Quarterly Financial Data (Unaudited)
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 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 |
|
14.13. Fair Value Measurements
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 — UnadjustedInputs are 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 may 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,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 disclosuresdisclosures; 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 trusttrusts 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 TrustTrusts and Other Special Use Funds The nuclear decommissioning trusttrusts 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 employee medical trust.account. See Note 2019 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'sagent’s internal operating controls and valuation processes.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 termshort-term instruments. These instruments are valued using active market prices or utilizing observable inputs described above.
Equity Securities
The nuclear decommissioning trust'strusts’ equity security investments are held indirectly through commingled funds. The commingled funds are valued using the funds'funds’ NAV as a practical expedient. The funds'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'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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The nuclear decommissioning trusttrusts 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value Tables The following table presents the fair value at December 31, 20192021, 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 | $ | — | | | $ | 115,079 | | | $ | — | | | $ | (4,690) | | | (a) | | $ | 110,389 | | Nuclear decommissioning trust: | | | | | | | | | | | | Equity securities | 45,264 | | | — | | | — | | | (27,782) | | | (b) | | 17,482 | | U.S. commingled equity funds | — | | | — | | | — | | | 595,048 | | | (c) | | 595,048 | | U.S. Treasury debt | 240,745 | | | — | | | — | | | — | | | | | 240,745 | | Corporate debt | — | | | 203,454 | | | — | | | — | | | | | 203,454 | | Mortgage-backed securities | — | | | 155,574 | | | — | | | — | | | | | 155,574 | | Municipal bonds | — | | | 72,189 | | | — | | | — | | | | | 72,189 | | Other fixed income | — | | | 10,265 | | | — | | | — | | | | | 10,265 | | Subtotal nuclear decommissioning trust | 286,009 | | | 441,482 | | | — | | | 567,266 | | | | | 1,294,757 | | | | | | | | | | | | | | Other special use funds: | | | | | | | | | | | | | | | | | | | | | | | | Equity securities | 47,570 | | | — | | | — | | | 936 | | | (b) | | 48,506 | | U.S. Treasury debt | 298,170 | | | — | | | — | | | — | | | | | 298,170 | | Municipal bonds | — | | | 11,734 | | | — | | | — | | | | | 11,734 | | Subtotal other special use funds | 345,740 | | | 11,734 | | | — | | | 936 | | | | | 358,410 | | | | | | | | | | | | | | Total assets | $ | 631,749 | | | $ | 568,295 | | | $ | — | | | $ | 563,512 | | | | | $ | 1,763,556 | | Liabilities | | | | | | | | | | | | Risk management activities — derivative instruments: | | | | | | | | | | | | Commodity contracts | $ | — | | | $ | (4,740) | | | $ | (2,738) | | | $ | 3,105 | | | (a) | | $ | (4,373) | |
(a)Represents counterparty netting, margin, and collateral. See Note 16. (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.
| | | | | | | | | | | | | | | | | | | | | | |
| 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. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the fair value at December 31, 20182020, 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 | $ | — | | | $ | 9,016 | | | $ | 4 | | | $ | (4,271) | | | (a) | | $ | 4,749 | | Nuclear decommissioning trust: | | | | | | | | | | | | Equity securities | 29,796 | | | — | | | — | | | (17,828) | | | (b) | | 11,968 | | U.S. commingled equity funds | — | | | — | | | — | | | 610,055 | | | (c) | | 610,055 | | U.S. Treasury debt | 164,514 | | | — | | | — | | | — | | | | | 164,514 | | Corporate debt | — | | | 149,509 | | | — | | | — | | | | | 149,509 | | Mortgage-backed securities | — | | | 99,623 | | | — | | | — | | | | | 99,623 | | Municipal bonds | — | | | 89,705 | | | — | | | — | | | | | 89,705 | | Other fixed income | — | | | 13,061 | | | — | | | — | | | | | 13,061 | | Subtotal nuclear decommissioning trust | 194,310 | | | 351,898 | | | — | | | 592,227 | | | | | 1,138,435 | | | | | | | | | | | | | | Other special use funds: | | | | | | | | | | | | Equity securities | 37,337 | | | — | | | — | | | 504 | | | (b) | | 37,841 | | U.S. Treasury debt | 203,220 | | | — | | | — | | | — | | | | | 203,220 | | Municipal bonds | — | | | 13,448 | | | — | | | — | | | | | 13,448 | | Subtotal other special use funds | 240,557 | | | 13,448 | | | — | | | 504 | | | | | 254,509 | | | | | | | | | | | | | | Total assets | $ | 434,867 | | | $ | 374,362 | | | $ | 4 | | | $ | 588,460 | | | | | $ | 1,397,693 | | Liabilities | | | | | | | | | | | | Risk management activities — derivative instruments: | | | | | | | | | | | | Commodity contracts | $ | — | | | $ | (20,498) | | | $ | (1,107) | | | $ | 2,986 | | | (a) | | $ | (18,619) | |
| | | | | | | | | | | | | | | | | | | | | | |
| 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 16. | | (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. |
(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.quote or other characteristics of the product. 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 (seetreatment. See Note 4).4.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 0 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$9 million as of December 31, 2019,2021, 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
15.14. Earnings Per Share
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): | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | 2019 | Net income attributable to common shareholders | $ | 618,720 | | | $ | 550,559 | | | $ | 538,320 | | Weighted average common shares outstanding — basic | 112,910 | | | 112,666 | | | 112,443 | | Net effect of dilutive securities: | | | | | | Contingently issuable performance shares and restricted stock units | 282 | | | 276 | | | 315 | | Weighted average common shares outstanding — diluted | 113,192 | | | 112,942 | | | 112,758 | | Earnings per weighted-average common share outstanding | | | | | | Net income attributable to common shareholders — basic | $ | 5.48 | | | $ | 4.89 | | | $ | 4.79 | | Net income attributable to common shareholders — diluted | $ | 5.47 | | | $ | 4.87 | | | $ | 4.77 | |
| | | | | | | | | | | | | | 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 |
|
16.15. Stock-Based Compensation
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 20122021 Long-Term Incentive Plan (“20122021 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 20122021 Plan authorizes up to 4.61.5 million common shares to be available for grant. As of December 31, 2019, 1.62021, 1.2 million common shares were available for issuance under the 20122021 Plan. During 2019, 2018,2021, 2020, and 2017,2019, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2012 to May 2021 were issued under the 2012 Long-Term Incentive Plan (“2012 Plan”), and awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no. No new awards may be granted under the 2012 or 2007 Plan.Plans.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock-Based Compensation Expense and Activity Compensation cost included in net income for stock-based compensation plans was $18 million in 2019, $202021, $18 million in 2018,2020, and $21$18 million in 2017.2019. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $3 million in 2021, $4 million in 2020, and $7 million in 2019, $7 million in 2018, and $15 million in 2017.2019.
As of December 31, 2019,2021, there were approximately $9$11 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 $22 million in 2021, $22 million in 2020 and $21 million in 2019, $24 million in 2018 and $22 million in 2017.2019.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table is a summary of awards granted and the weighted-average grant date fair value for each of the last three years ended 2019, 2018years:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Restricted Stock Units, Stock Grants, and Stock Units (a) | | Performance Shares (b) | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | Units granted | 152,345 | | | 118,403 | | | 109,106 | | | 161,840 | | | 122,830 | | | 142,874 | | Weighted-average grant date fair value | $ | 76.72 | | | $ | 71.70 | | | $ | 89.15 | | | $ | 82.42 | | | $ | 104.74 | | | $ | 92.16 | |
(a)Units granted includes awards that will be cash settled of 51,074 in 2021, 45,646 in 2020, and 2017:48,972 in 2019.
(b)Reflects the target payout level.
| | | | | | | | | | | | | | | | | | | | | | | | | | 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. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table is a summary of the status of non-vested awards as of December 31, 20192021, 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, 2021 | 220,557 | | | $ | 77.93 | | | 260,004 | | | $ | 98.28 | | Granted | 152,345 | | | 76.72 | | | 161,840 | | | 82.42 | | Vested | (115,099) | | | 80.50 | | | (136,070) | | | 92.16 | | Forfeited (c) | (4,647) | | | 80.11 | | | (5,092) | | | 95.07 | | Nonvested at December 31, 2021 | 253,156 | | (a) | 79.37 | | | 280,682 | | | 92.16 | | Vested Awards Outstanding at December 31, 2021 | 88,706 | | | 0 | | 136,070 | | | 0 |
| | | | | | | | | | | | | | | | 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 118,538 of awards that will be cash settled. | | (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. |
(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 $4 million, $6 million, and $5 million $4 millionin 2021, 2020 and $4 million in 2019, 2018 and 2017, respectively. This includes cash used to settle restricted stock units of $3 million, $4 million, and $5 million $5 millionin 2021, 2020 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'semployee’s retirement. Awardees typically 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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'sCompany’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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 2 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'sWest’s total shareholder return ("TSR"(“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. Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17.16. Derivative Accounting
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.natural gas. 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 1413 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 (seeRate. See Note 4).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 hadThe following table shows the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
| | | | Quantity | | Quantity | Commodity | | Unit of Measure | December 31, 2019 | | December 31, 2018 | Commodity | | Unit of Measure | December 31, 2021 | | December 31, 2020 | Power | | GWh | 193 |
| | 250 |
| Power | | GWh | — | | | 368 | | Gas | | Billion cubic feet | 257 |
| | 218 |
| Gas | | Billion cubic feet | 155 | | | 205 | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Gains and Losses from Derivative Instruments The following table provides information about APS’s gains and losses from derivative instruments in designated cash flow accounting hedging relationships during(dollars in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Financial Statement | | Year Ended December 31, | Commodity Contracts | | Location | | 2021 | | 2020 | | 2019 | | | | | | | | | | Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a) | | Fuel and purchased power (b) | | $ | — | | | $ | (763) | | | $ | (1,512) | | | | | | | | | | |
(a)During the years ended December 31, 2021, 2020, and 2019, 2018 and 2017 (dollars in thousands):we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges. (b)Amounts are before the effect of PSA deferrals. | | | | | | | | | | | | | | | | | | 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 0 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 taxesno amounts will be reclassified from accumulated OCI as an offset tointo income. For APS, the effectdelivery period for all derivative instruments in designated cash flow accounting hedging relationships have lapsed.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 | | 2021 | | 2020 | | 2019 | | | | | | | | | | Net Gain (Loss) Recognized in Income | | Fuel and purchased power (a) | | $ | 216,847 | | | $ | (3,178) | | | $ | (84,953) | | | | | | | | | | |
(a)Amounts are before the effect of PSA deferrals. | | | | | | | | | | | | | | | | | | 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'scounterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.offsetting. 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, 2021: (dollars in thousands) | | Gross Recognized Derivatives (a) | | Amounts Offset (b) | | Net Recognized Derivatives | | Other (c) | | Amounts Reported on Balance Sheets | Current assets | | $ | 66,777 | | | $ | (3,346) | | | $ | 63,431 | | | $ | 50 | | | $ | 63,481 | | Investments and other assets | | 48,302 | | | (1,394) | | | 46,908 | | | — | | | 46,908 | | Total assets | | 115,079 | | | (4,740) | | | 110,339 | | | 50 | | | 110,389 | | | | | | | | | | | | | Current liabilities | | (6,084) | | | 3,346 | | | (2,738) | | | (1,635) | | | (4,373) | | Deferred credits and other | | (1,394) | | | 1,394 | | | — | | | — | | | — | | Total liabilities | | (7,478) | | | 4,740 | | | (2,738) | | | (1,635) | | | (4,373) | | Total | | $ | 107,601 | | | $ | — | | | $ | 107,601 | | | $ | (1,585) | | | $ | 106,016 | |
(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 $1,635 and cash margin provided to counterparties of $50.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As of December 31, 2020: (dollars in thousands) | | Gross Recognized Derivatives (a) | | Amounts Offset (b) | | Net Recognized Derivatives | | Other (c) | | Amounts Reported on Balance Sheets | Current assets | | $ | 5,870 | | | $ | (2,939) | | | $ | 2,931 | | | $ | — | | | $ | 2,931 | | Investments and other assets | | 3,150 | | | (1,332) | | | 1,818 | | | — | | | 1,818 | | Total assets | | 9,020 | | | (4,271) | | | 4,749 | | | — | | | 4,749 | | | | | | | | | | | | | Current liabilities | | (9,211) | | | 2,939 | | | (6,272) | | | (1,285) | | | (7,557) | | Deferred credits and other | | (12,394) | | | 1,332 | | | (11,062) | | | — | | | (11,062) | | Total liabilities | | (21,605) | | | 4,271 | | | (17,334) | | | (1,285) | | | (18,619) | | Total | | $ | (12,585) | | | $ | — | | | $ | (12,585) | | | $ | (1,285) | | | $ | (13,870) | |
(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 $1,285.
| | | | | | | | | | | | | | | | | | | | | | 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) | NaN 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. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | 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) | NaN 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, 2019,2021, we have three counterparties for which our exposure represents approximately 38% of Pinnacle West has no counterparties with positive exposures of greater than 10%West’s $110 million of risk management assets. This exposure relates to master agreements with counterparties and all three are rated as investment grade. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of our 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).
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 fromDecember 31, 2021 | Aggregate fair value of derivative instruments in a net liability position | $ | 7,478 | | Cash collateral posted | — | | Additional cash collateral in the derivative details above.event credit-risk related contingent features were fully triggered (a) | 2,658 | |
(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$88 million if our debt credit ratings were to fall below investment grade.
18.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. Other Income and Other Expense The following table provides detail of Pinnacle West'sWest’s Consolidated other income and other expense for 2019, 20182021, 2020 and 20172019 (dollars in thousands): | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | 2019 | Other income: | | | | | | Interest income | $ | 6,726 | | | $ | 12,210 | | | $ | 10,377 | | Investment gains (losses) — net | — | | | 2,358 | | | — | | Debt return on Four Corners SCR deferral (Note 4) | 14,955 | | | 15,865 | | | 19,541 | | Debt return on Ocotillo modernization project (Note 4) | 23,366 | | | 26,121 | | | 20,282 | | Miscellaneous | 53 | | | 149 | | | 63 | | Total other income | $ | 45,100 | | | $ | 56,703 | | | $ | 50,263 | | Other expense: | | | | | | Non-operating costs | $ | (13,008) | | | $ | (12,400) | | | $ | (10,663) | | Investment gains (losses) — net | (1,367) | | | — | | | (1,835) | | Miscellaneous | (11,021) | | | (45,376) | | (a) | (5,382) | | Total other expense | $ | (25,396) | | | $ | (57,776) | | | $ | (17,880) | |
| | | | | | | | | | | | | | 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 | ) |
(a)The 2020 miscellaneous amount includes donations of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan. See Note 4.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Income and Other Expense - APS The following table provides detail of APS’s other income and other expense for 2019, 20182021, 2020 and 20172019 (dollars in thousands): | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | 2019 | Other income: | | | | | | Interest income | $ | 4,692 | | | $ | 9,621 | | | $ | 6,998 | | Debt return on Four Corners SCR deferral (Note 4) | 14,955 | | | 15,865 | | | 19,541 | | Debt return on Ocotillo modernization project (Note 4) | 23,366 | | | 26,121 | | | 20,282 | | Miscellaneous | 40 | | | 148 | | | 63 | | Total other income | $ | 43,053 | | | $ | 51,755 | | | $ | 46,884 | | Other expense: | | | | | | Non-operating costs | $ | (10,080) | | | $ | (10,659) | | | $ | (9,612) | | | | | | | | Miscellaneous | (8,817) | | | (43,035) | | (a) | (3,378) | | Total other expense | $ | (18,897) | | | $ | (53,694) | | | $ | (12,990) | |
| | | | | | | | | | | | | | 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 | ) |
(a)The 2020 miscellaneous amount includes donations of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan. See Note 4.
19.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
18. Palo Verde Sale Leaseback Variable Interest Entities In 1986, APS entered into agreements with 3 separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. Prior to April 1, 2021, the lease terms allowed APS willthe right to retain the assets through 2023 under 1 lease and 2033 under the other 2 leases. On April 1, 2021, APS executed an amended lease agreement with one of the VIE lessor trust entities relating to the lease agreement with the term ending in 2023. The amendment extends the lease term for this lease through 2033 and changes the lease payment. As a result of this amendment, APS will now retain the assets through 2033 under all three lease agreements. APS will be required to make payments relating to these the 3 leases in total of approximately $23$21 million annually for the period 2020 through 2023, and about $16 million annually for the period 20242022 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'leases’ terms give APS the ability to utilize the assets for a significant portion of the assets'assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs'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 $17 million for 2021, and $19 million for 2019, 20182020 and 2017.2019. 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 |
|
| | | | | | | | | | | | | December 31, 2021 | | December 31, 2020 | Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation | $ | 94,166 | | | $ | 98,036 | | Equity-Noncontrolling interests | 115,260 | | | 119,290 | |
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be 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$315 million beginning in 2020,2022, and up to $456$501 million over the lease extension term.terms. 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.
20.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
19. Investments in Nuclear Decommissioning Trusts and Other Special Use Funds We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Accounts,Account, 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 1413 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 — - ToAPS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations.Verde. 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)credit losses) 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)credit losses) in other regulatory liabilities. Activities relating to APS coal mine 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 Company2021 and 2020, APS was reimbursed $15 million and $14 million, respectively, 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)credit losses) in other regulatory liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the tablestable below. On January 4, 2021, an additional $106 million of investments were transferred from APS other postretirement benefit trust assets into the active union employee medical account, see Note 8.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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'sAPS’s nuclear decommissioning trusttrusts and other special use fund assets at December 31, 2019 and December 31, 2018 (dollars in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2021 | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | Investment Type: | Nuclear Decommissioning Trusts | | Other Special Use Funds | | Total | | | Equity securities | $ | 640,312 | | | $ | 47,570 | | | $ | 687,882 | | | $ | 451,387 | | | $ | — | | Available for sale-fixed income securities | 682,227 | | | 309,904 | | | 992,131 | | (a) | 24,283 | | | (4,063) | | Other | (27,782) | | | 936 | | | (26,846) | | (b) | — | | | — | | Total | $ | 1,294,757 | | | $ | 358,410 | | | $ | 1,653,167 | | | $ | 475,670 | | | $ | (4,063) | |
| | | | | | | | | | | | | | | | | | | | |
| 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, 2021, the amortized cost basis of these available-for-sale investments is $972 million. | | (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. |
(b)Represents net pending securities sales and purchases.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | December 31, 2020 | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | Investment Type: | Nuclear Decommissioning Trusts | | Other Special Use Funds | | Total | | | Equity securities | $ | 639,851 | | | $ | 37,337 | | | $ | 677,188 | | | $ | 421,666 | | | $ | — | | Available for sale-fixed income securities | 516,412 | | | 216,668 | | | 733,080 | | (a) | 46,581 | | | (398) | | Other | (17,828) | | | 504 | | | (17,324) | | (b) | — | | | — | | Total | $ | 1,138,435 | | | $ | 254,509 | | | $ | 1,392,944 | | | $ | 468,247 | | | $ | (398) | |
(a)As of December 31, 2020, the amortized cost basis of these available-for-sale investments is $687 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. |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth APS'sAPS’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 | 2021 | | | | | | Realized gains | $ | 134,610 | | | $ | 49 | | | $ | 134,659 | | Realized losses | (8,431) | | | (7) | | | (8,438) | | Proceeds from the sale of securities (a) | 1,457,305 | | | 263,661 | | | 1,720,966 | | 2020 | | | | | | Realized gains | 12,194 | | | 176 | | | 12,370 | | Realized losses | (5,553) | | | (15) | | | (5,568) | | Proceeds from the sale of securities (a) | 675,035 | | | 144,484 | | | 819,519 | | 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 | |
| | | | | | | | | | | | | | 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 and other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union employee medical account. | | (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 APS’s fixed income securities, summarized by contractual maturities, at December 31, 20192021, is as follows (dollars in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | Nuclear Decommissioning Trusts | | Coal Reclamation Escrow Account | | Active Union Employee Medical Account | | Total | Less than one year | $ | 31,070 | | | $ | 36,852 | | | $ | 40,870 | | | $ | 108,792 | | 1 year – 5 years | 195,975 | | | 41,931 | | | 158,235 | | | 396,141 | | 5 years – 10 years | 155,202 | | | 1,775 | | | 21,846 | | | 178,823 | | Greater than 10 years | 299,980 | | | 8,395 | | | — | | | 308,375 | | Total | $ | 682,227 | | | $ | 88,953 | | | $ | 220,951 | | | $ | 992,131 | |
| | | | | | | | | | | | | | | | | | 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 |
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
21.20. Changes in Accumulated Other Comprehensive Loss
The following table shows the changes in Pinnacle West'sWest’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 at December 31, 2019 | $ | (56,522) | | | | | $ | (574) | | | | | $ | (57,096) | | OCI (loss) before reclassifications | (8,370) | | | | | (2,089) | | | | | (10,459) | | Amounts reclassified from accumulated other comprehensive loss | 4,167 | | | (a) | | 592 | | | (b) | | 4,759 | | | | | | | | | | | | Balance at December 31, 2020 | (60,725) | | | | | (2,071) | | | | | (62,796) | | OCI (loss) before reclassifications | 2,439 | | | | | 1,077 | | | | | 3,516 | | Amounts reclassified from accumulated other comprehensive loss | 4,401 | | | (a) | | 18 | | | (b) | | 4,419 | | | | | | | | | | | | Balance at December 31, 2021 | $ | (53,885) | | | | | $ | (976) | | | | | $ | (54,861) | |
| | | | | | | | | | | | | | | | | | 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. |
(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 16.
Changes in Accumulated Other Comprehensive Loss -— APS The following table shows the changes in APS'sAPS’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 at December 31, 2019 | $ | (34,948) | | | | | $ | (574) | | | | | $ | (35,522) | | OCI (loss) before reclassifications | (9,568) | | | | | (18) | | | | | (9,586) | | Amounts reclassified from accumulated other comprehensive loss | 3,598 | | | (a) | | 592 | | | (b) | | 4,190 | | | | | | | | | | | | Balance at December 31, 2020 | (40,918) | | | | | — | | | | | (40,918) | | OCI (loss) before reclassifications | 2,043 | | | | | (18) | | | | | 2,025 | | Amounts reclassified from accumulated other comprehensive loss | 3,995 | | | (a) | | 18 | | | (b) | | 4,013 | | | | | | | | | | | | Balance at December 31, 2021 | $ | (34,880) | | | | | $ | — | | | | | $ | (34,880) | |
(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 16. | | | | | | | | | | | | | | | | | | 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. |
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 |
|
| | | | | | | | | | | | | | | | | | | Year Ended December 31, | | 2021 | | 2020 | | 2019 | | | | | | | Operating expenses | $ | 10,245 | | | $ | 7,901 | | | $ | 12,451 | | | | | | | | Other | | | | | | Equity in earnings of subsidiaries | 628,916 | | | 566,147 | | | 562,946 | | Other expense | (4,919) | | | (4,586) | | | (3,957) | | Total | 623,997 | | | 561,561 | | | 558,989 | | Interest expense | 10,672 | | | 14,021 | | | 15,069 | | Income before income taxes | 603,080 | | | 539,639 | | | 531,469 | | Income tax benefit | (15,640) | | | (10,920) | | | (6,851) | | Net income attributable to common shareholders | 618,720 | | | 550,559 | | | 538,320 | | Other comprehensive income (loss) — attributable to common shareholders | 7,935 | | | (5,700) | | | (9,388) | | Total comprehensive income — attributable to common shareholders | $ | 626,655 | | | $ | 544,859 | | | $ | 528,932 | |
See Combined Notes to Consolidated Financial Statements.
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 |
|
| | | | | | | | | | | | | December 31, | | 2021 | | 2020 | ASSETS | | | | Current assets | | | | Cash and cash equivalents | $ | 594 | | | $ | 19 | | Accounts receivable | 125,457 | | | 123,980 | | | | | | Income tax receivable | 1,498 | | | 14,719 | | Other current assets | 13 | | | 298 | | Total current assets | 127,562 | | | 139,016 | | Investments and other assets | | | | Investments in subsidiaries | 6,797,528 | | | 6,400,339 | | Deferred income taxes | 19,520 | | | 7,589 | | Other assets | 57,608 | | | 52,595 | | Total investments and other assets | 6,874,656 | | | 6,460,523 | | Total Assets | $ | 7,002,218 | | | $ | 6,599,539 | | LIABILITIES AND EQUITY | | | | Current liabilities | | | | Accounts payable | $ | 3,071 | | | $ | 5,669 | | Accrued taxes | 19,855 | | | 16,998 | | Common dividends payable | 95,988 | | | 93,531 | | Short-term borrowings | 13,300 | | | 169,000 | | Current maturities of long-term debt | 150,000 | | | — | | Operating lease liabilities | 107 | | | 90 | | Other current liabilities | 14,684 | | | 15,306 | | Total current liabilities | 297,005 | | | 300,594 | | | | | | Long-term debt less current maturities (Note 7) | 647,139 | | | 496,321 | | | | | | | | | | | | | | Pension liabilities | 14,537 | | | 17,541 | | Operating lease liabilities | 1,576 | | | 1,683 | | Other | 20,501 | | | 30,607 | | Total deferred credits and other | 36,614 | | | 49,831 | | COMMITMENTS AND CONTINGENCIES (SEE NOTES) | 0 | | 0 | Common stock equity | | | | Common stock | 2,696,342 | | | 2,671,193 | | Accumulated other comprehensive loss | (54,861) | | | (62,796) | | Retained earnings | 3,264,719 | | | 3,025,106 | | Total Pinnacle West Shareholders’ equity | 5,906,200 | | | 5,633,503 | | Noncontrolling interests | 115,260 | | | 119,290 | | Total Equity | 6,021,460 | | | 5,752,793 | | Total Liabilities and Equity | $ | 7,002,218 | | | $ | 6,599,539 | |
See Combined Notes to Consolidated Financial Statements.
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 |
|
| | | | | | | | | | | | | | | | | | | Year Ended December 31, | | 2021 | | 2020 | | 2019 | Cash flows from operating activities | | | | | | Net income | $ | 618,720 | | | $ | 550,559 | | | $ | 538,320 | | Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | Equity in earnings of subsidiaries — net | (628,916) | | | (566,147) | | | (562,946) | | Depreciation and amortization | 93 | | | 76 | | | 76 | | Deferred income taxes | (11,381) | | | 33,007 | | | (35,831) | | Accounts receivable | 8,897 | | | (7,903) | | | 182 | | Accounts payable | (2,598) | | | (1,964) | | | (2,129) | | Accrued taxes and income tax receivables — net | 16,079 | | | 9,610 | | | 16,400 | | Dividends received from subsidiaries | 376,500 | | | 357,500 | | | 336,300 | | Other | 4,214 | | | 20,163 | | | (1,300) | | Net cash flow provided by operating activities | 381,608 | | | 394,901 | | | 289,072 | | Cash flows from investing activities | | | | | | | | | | | | Investments in subsidiaries | (145,266) | | | (137,881) | | | 1,557 | | Repayments of loans from subsidiaries | 4,017 | | | 932 | | | 4,190 | | Advances of loans to subsidiaries | (12,256) | | | (7,261) | | | (4,165) | | Net cash flow provided by (used for) investing activities | (153,505) | | | (144,210) | | | 1,582 | | Cash flows from financing activities | | | | | | Issuance of long-term debt | 300,000 | | | 496,950 | | | — | | Short-term debt borrowings under revolving credit facility | — | | | 211,690 | | | 49,000 | | Short-term debt repayments under revolving credit facility | (19,000) | | | (230,690) | | | (65,000) | | Short-term borrowings and (repayments) — net | (136,700) | | | 73,325 | | | 54,275 | | Dividends paid on common stock | (369,478) | | | (350,577) | | | (329,643) | | Repayment of long-term debt | — | | | (450,000) | | | — | | Common stock equity issuance and purchases — net | (2,350) | | | (1,389) | | | 692 | | | | | | | | Net cash flow used for financing activities | (227,528) | | | (250,691) | | | (290,676) | | Net decrease in cash and cash equivalents | 575 | | | — | | | (22) | | Cash and cash equivalents at beginning of year | 19 | | | 19 | | | 41 | | Cash and cash equivalents at end of year | $ | 594 | | | $ | 19 | | | $ | 19 | |
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.
The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of Pinnacle West Capital Corporation on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method. PINNACLE WEST CAPITAL CORPORATION
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 |
|
Table of Contents
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 |
|
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES (a)Disclosure Controls and Procedures The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78a et seq.) is recorded, processed, summarized, and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of December 31, 2019.2021. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective. APS’s management, with the participation of APS’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’s disclosure controls and procedures as of December 31, 2019.2021. Based on that evaluation, APS’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’s disclosure controls and procedures were effective. (b)Management’s Annual Reports on Internal Control Over Financial Reporting Reference is made to “Management’s Report on Internal Control over Financial Reporting (Pinnacle West Capital Corporation)” in Item 8 of this report and “Management’s Report on Internal Control over Financial Reporting (Arizona Public Service Company)” in Item 8 of this report. (c)Attestation Reports of the Registered Public Accounting Firm Reference is made to “Report of Independent Registered Public Accounting Firm” in Item 8 of this report and “Report of Independent Registered Public Accounting Firm” in Item 8 of this report on the internal control over financial reporting of Pinnacle West Capital Corporation and Arizona Public Service Company,APS, respectively. (d)Changes In Internal Control Over Financial Reporting No change in Pinnacle West’s or APS’s internal control over financial reporting occurred during the fiscal quarter ended December 31, 20192021, that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF PINNACLE WEST
Reference is hereby made to “Information About Our Board and Corporate Governance” and “Proposal 1 — Election of Directors” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 20, 202018, 2022 (the “2020“2022 Proxy Statement”) and to the “Information about our Executive Officers” section in Part I of this report. Pinnacle West has adopted a Code of Ethics for Financial Executives that applies to financial executives including Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Controller, Treasurer, and General Counsel, the President and Chief Operating Officer of APS and other persons designated as financial executives by the Chair of the Audit Committee. The Code of Ethics for Financial Executives is posted on Pinnacle West’s website (www.pinnaclewest.com). Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Executives by posting such information on Pinnacle West’s website. ITEM 11. EXECUTIVE COMPENSATION Reference is hereby made to “Director Compensation,” “Executive Compensation,” and “Human Resources Committee Interlocks and Insider Participation” in the 20202022 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Reference is hereby made to “Ownership of Pinnacle West Stock” in the 20202022 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans The following table sets forth information as of December 31, 20192021, with respect to the the 2021 Plan, 2012 Plan, and the 2007 Plan, under which our equity securities are outstanding or currently authorized for issuance.
Equity Compensation Plan Information | | Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | | Weighted- average exercise price of outstanding options, warrants and rights (b) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) | Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) | | Weighted- average exercise price of outstanding options, warrants and rights (b) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) | Equity compensation plans approved by security holders | 1,267,062 |
| | — |
| | 1,645,994 |
| Equity compensation plans approved by security holders | 1,243,225 | | | — | | | 1,241,996 | | Equity compensation plans not approved by security holders | | | — |
| | | Equity compensation plans not approved by security holders | — | | | — | | | — | | Total | 1,267,062 |
| | — |
| | 1,645,994 |
| Total | 1,243,225 | | | — | | | 1,241,996 | |
| | (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. |
(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 2021 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 2012 Plan and the 2007 Plan. However, if an award under the 2012 Plan or the 2007 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 2021 Plan.
Equity Compensation Plans Approved By Security Holders Amounts in column (a) in the table above include shares subject to awards outstanding under twothree equity compensation plans that were previously approved by our shareholders: (a) the 2007 Plan, which was approved by our shareholders at our 2007 annual meeting of shareholders and under which no new stock awards may be granted; and (b) the 2012 Plan, as amended, which was approved by our shareholders at our 2012 annual meeting of shareholders and the first amendment to the 2012 Plan was approved by our shareholders at our 2017 annual meeting of shareholders and under which no new stock awards may be granted; and (c) the 2021 Plan which was approved by our shareholders at our 2021 annual meeting of shareholders. See Note 1615 of the Notes to Consolidated Financial Statements for additional information regarding these plans.
Equity Compensation Plans Not Approved by Security Holders The Company does not have any equity compensation plans under which shares can be issued that have not been approved by the shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Reference is hereby made to “Information About Our Board and Corporate Governance” and “Related Party Transactions” in the 20202022 Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Pinnacle West Reference is hereby made to “Audit Matters — Audit Fees and — Pre-Approval Policies” in the 20202022 Proxy Statement. APS The following fees were paid to APS’s independent registered public accountants, Deloitte & Touche LLP, for the last two fiscal years: | | Type of Service | | 2019 | | 2018 | Type of Service | | 2021 | | 2020 | Audit Fees (1) | | $ | 2,328,565 |
| | $ | 2,342,455 |
| Audit Fees (1) | | $ | 2,580,260 | | | $ | 2,414,909 | | Audit-Related Fees (2) | | 322,917 |
| | 300,334 |
| Audit-Related Fees (2) | | 333,905 | | | 323,067 | | |
(1) The aggregate fees billed for services rendered for the audit of annual financial statements and for review of financial statements included in Reports on Form 10-Q. (2) The aggregate fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the financial statements and are not included in Audit Fees reported above, which primarily consist of fees for employee benefit plan audits performed in 20192021 and 2018.2020. Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by APS’s registered public accounting firm. The Audit Committee has delegated to the Chair of the Audit Committee the authority to pre-approve audit and non-audit services to be performed by the independent public accountants if the services are not expected to cost more than $50,000.$100,000. The Chair must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the services performed by Deloitte & Touche LLP for APS in 20192021 were pre-approved by the Audit Committee or the Chair consistent with the pre-approval policy.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Financial Statement Schedules See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8. Exhibits Filed The documents listed below are being filed or have previously been filed on behalf of Pinnacle West or APS and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith. | | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | | | | | | | | | | Exhibit
No. 3.1 | | Registrant(s)Pinnacle West | | Description | | Previously Filed as Exhibit: a
| | Date Filed | | | | | | | | | | 3.1 | | Pinnacle West | | | | 3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962 | | 8/7/2008 | | | | | | | | | | 3.2 | | Pinnacle West | | | | 3.1 to Pinnacle West/APS February 28, 201725, 2020 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 2/28/201725/2020 | | | | | | | | | | 3.3 | | APS | | Articles of Incorporation, restated as of May 25, 1988 | | 4.2 to APS’s Form 18 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473 | | 9/29/1993 | | | | | | | | | | 3.3.1 | | APS | | | | 3.1 to Pinnacle West/APS May 22, 2012 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 5/22/2012 | | | | | | | | | | 3.4 | | APS | | | | 3.4 to Pinnacle West/APS December 31, 2008 Form 10-K, File No. 1-4473 | | 2/20/2009 | | | | | | | | | | 4.1 | | Pinnacle West | | | | 4.1 to Pinnacle West June 20, 2017 Form 8-K Report, File No. 1-8962
| | 6/20/2017
| | | | | | | | | | 4.2 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.6 to APS’s Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473 | | 1/11/1995 | | | | | | | | | | 4.2a4.3 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.4 to APS’s Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473 | | 1/11/1995 | | | | | | | | | | 4.3 | | Pinnacle West
APS
| | | | 4.5 to APS’s Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333- 15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473 | | 11/22/1996 | | | | | | | | | |
| | | | | | | | | | Exhibit
No. 4.4 | | Registrant(s)Pinnacle West | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 4.3a | | Pinnacle West
APS
| | | | 4.6 to APS’s Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473 | | 11/22/1996 | | | | | | | | | | 4.3b | | Pinnacle West
APS
| | | | 4.10 to APS’s Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report, File No. 1-4473 | | 4/9/1997 | | | | | | | | | | 4.3c | | Pinnacle West
APS
| | | | 10.2 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962 | | 5/15/2003 | | | | | | | | | | 4.4 | | Pinnacle West | | | | 4.1 to Pinnacle West’s Registration Statement No. 333-52476 | | 12/21/2000 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | 4.4aExhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 4.4a | | Pinnacle West | | | | 4.1 to Pinnacle West November 30, 2017June 10, 2020 Form 8-K Report, File No. 1-8962 | | 11/30/20176/16/2020 | | | | | | | | | | 4.5 | | Pinnacle West | | | | 4.2 to Pinnacle West’s Registration Statement No. 333-52476 | | 12/21/2000 | | | | | | | | | | 4.6 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.10 to APS’s Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report, File No. 1-4473 | | 1/16/1998 | | | | | | | | | | 4.6a | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.1 to APS’s Registration Statement No. 333-90824 by means of May 7, 2003 Form 8-K Report, File No. 1-4473 | | 5/9/2003 | | | | | | | | | | 4.6b | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.1 to APS’s Registration Statement No. 333-106772 by means of June 24, 2004 Form 8-K Report, File No. 1-4473 | | 6/28/2004 | | | | | | | | | | 4.6c | | Pinnacle West
APS
| | | | 4.1 to APS’s Registration Statements Nos. 333-106772 and 333-121512 by means of August 17, 2005 Form 8-K Report, File No. 1-4473 | | 8/22/2005 | | | | | | | | | | 4.6d4.6c | | APS | | | | 4.1 to APS’s July 31, 2006 Form 8-K Report, File No. 1-4473 | | 8/3/2006 | | | | | | | | | | 4.6e4.6d | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.6e to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/20/2015 | | | | | | | | | | 4.6f | | Pinnacle West
APS
| | | | 4.6f to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/20/2015 | | | | | | | | | | 4.6g4.6e | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.6g to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/20/2015 |
| | | | | | | | | | Exhibit
No. 4.6f | | Registrant(s)Pinnacle West APS | | Description | | Previously Filed as Exhibit: a
| | Date Filed | | | | | | | | | | 4.6h | | Pinnacle West
APS
| | | | 4.6h to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/20/2015 | | | | | | | | | | 4.6i4.6g | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.6i to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/20/2015 | | | | | | | | | | 4.6j4.6h | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.6j to Pinnacle West/APS 2014 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/20/2015 | | | | | | | | | | 4.6k | | Pinnacle West
APS
| | | | 4.1 to Pinnacle West/APS May 14, 2015 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 5/19/2015 | | | | | | | | | | 4.6l4.6i | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.1 to Pinnacle West/APS November 3, 2015 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 11/6/2015 | | | | | | | | | | 4.6m4.6j | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.1 to Pinnacle West/APS May 3, 2016 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 5/6/2016 | | | | | | | | | | 4.6n4.6k | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.1 to Pinnacle West/APS September 15, 2016 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 9/20/2016 | | | | | | | | | | 4.6o4.6l | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.1 to Pinnacle West/APS September 11, 2017 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 9/11/2017 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | 4.6pExhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 4.6m | | Pinnacle West APS
| | | | 4.1 to Pinnacle West/APS August 9, 2018 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 8/9/2018 | | | | | | | | | | 4.6q4.6n | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.1 to Pinnacle West/APS February 28, 2019 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 2/28/2019 | | | | | | | | | | 4.6r4.6o | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.1 to Pinnacle West/APS August 16, 2019 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 8/16/2019 | | | | | | | | | | 4.6s4.6p | | Pinnacle West APS | | Pinnacle West
APS
| | | | 4.1 to Pinnacle West/APS November 20, 2019 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 11/20/2019 | | | | | | | | | | 4.74.6q | | Pinnacle West APS | | | | 4.1 to Pinnacle West/APS May 22, 2020 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 5/22/2020 | | | | | | | | | | 4.6r | | Pinnacle West APS | | | | 4.1 to Pinnacle West/APS September 11, 2020 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 9/11/2020 | 4.6s | | Pinnacle West APS | | | | 4.1 to Pinnacle West/APS August 16, 2021 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 8/16/2021 | | | | | | | | | | 4.7 | | Pinnacle West | | | | 4.4 to Pinnacle West’s June 23, 2004 Form 8-K Report, File No. 1-8962 | | 8/9/2004 | | | | | | | | | | 4.7a | | Pinnacle West | | | | 4.1 to Pinnacle West’s Form S-3 Registration Statement No. 333-155641, File No. 1-8962 | | 11/25/2008 | | | | | | | | | | 4.8 | | Pinnacle West | | Agreement, dated March 29, 1988, relating to the filing of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company’s total assets | | 4.1 to Pinnacle West’s 1987 Form 10-K Report, File No. 1-8962 | | 3/30/1988 | | | | | | | | | |
| | | | | | | | | | Exhibit
No. 4.8a | | Registrant(s)Pinnacle West APS | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 4.8a | | Pinnacle West
APS
| | | | 4.1 to APS’s 1993 Form 10-K Report, File No. 1-4473 | | 3/30/1994 | | | | | | | | | | 4.9 | | Pinnacle West APS | | Pinnacle West
APS
| | | | | | | | | | | | | | | | 10.1.1 | | Pinnacle West APS
| | Two separate Decommissioning Trust Agreements (relating to PVGS Units 1 and 3, respectively), each dated July 1, 1991, between APS and Mellon Bank, N.A., as Decommissioning Trustee | | 10.2 to APS’s September 30, 1991 Form 10-Q Report, File No. 1-4473 | | 11/14/1991 | | | | | | | | | | 10.1.1a | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1 to APS’s 1994 Form 10-K Report, File No. 1-4473 | | 3/30/1995 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | 10.1.1bExhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.1.1b | | Pinnacle West APS
| | | | 10.2 to APS’s 1994 Form 10-K Report, File No. 1-4473 | | 3/30/1995 | | | | | | | | | | 10.1.1c | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.4 to APS’s 1996 Form 10-K Report , File No. 1-4473 | | 3/28/1997 | | | | | | | | | | 10.1.1d | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.6 to APS’s 1996 Form 10-K Report, File No. 1-4473 | | 3/28/1997 | | | | | | | | | | 10.1.1e | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.2 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962 | | 5/15/2002 | | | | | | | | | | 10.1.1f | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.4 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962 | | 5/15/2002 | | | | | | | | | | 10.1.1g | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962 | | 3/15/2004 | | | | | | | | | | 10.1.1h | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.5 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962 | | 3/15/2004 | | | | | | | | | | 10.1.1i | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/9/2007 | | | | | | | | | | 10.1.1j | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.2 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 104473 | | 5/9/2007 | | | | | | | | | |
| | | | | | | | | | Exhibit
No. 10.1.2 | | Registrant(s) | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 10.1.2 | | Pinnacle West APS
| | Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2) dated as of January 31, 1992, among APS, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVGS Unit 2 | | 10.1 to Pinnacle West’s 1991 Form 10-K Report, File No. 1-8962 | | 3/26/1992 | | | | | | | | | | 10.1.2a | | Pinnacle West APS
| | First Amendment to Amended and Restated Decommissioning Trust Agreement (PVGS Unit 2), dated as of November 1, 1992 | | 10.2 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | 10.1.2bExhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.1.2b | | Pinnacle West APS
| | | | 10.3 to APS’s 1994 Form 10-K Report, File No. 1-4473 | | 3/30/1995 | | | | | | | | | | 10.1.2c | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1 to APS’s June 30, 1996 Form 10-Q Report, File No. 1-4473 | | 8/9/1996 | | | | | | | | | | 10.1.2d | | Pinnacle West APS | | Pinnacle West
APS
| | | | APS 10.5 to APS’s 1996 Form 10-K Report, File No. 1-4473 | | 3/28/1997 | | | | | | | | | | 10.1.2e | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962 | | 5/15/2002 | | | | | | | | | | 10.1.2f | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962 | | 5/15/2002 | | | | | | | | | | 10.1.2g | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.4 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962 | | 3/15/2004 | | | | | | | | | | 10.1.2h | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1.2h to Pinnacle West’s 2007 Form 10-K Report, File No. 1-8962 | | 2/27/2008 | | | | | | | | | | 10.2.1b | | Pinnacle West APS
| | Arizona Public Service Company Deferred Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987, respectively | | 10.4 to APS’s 1988 Form 10-K Report, File No. 1-4473 | | 3/8/1989 | | | | | | | | | | 10.2.1ab | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3A to APS’s 1993 Form 10-K Report, File No. 1-4473 | | 3/30/1994 | | | | | | | | | |
| | | | | | | | | | Exhibit
No.10.2.1bb
| | Registrant(s)Pinnacle West APS | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 10.2.1bb
| | Pinnacle West
APS
| | | | 10.2 to APS’s September 30, 1994 Form 10-Q Report, File No. 1-4473 | | 11/10/1994 | | | | | | | | | | 10.2.1cb | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3A to APS’s 1996 Form 10-K Report, File No. 1-4473 | | 3/28/1997 | | | | | | | | | | 10.2.1db | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.8A to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962 | | 3/14/2001 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.2.2b | | Pinnacle West APS
| | Arizona Public Service Company Directors’ Deferred Compensation Plan, as restated, effective January 1, 1986 | | 10.1 to APS’s June 30, 1986 Form 10-Q Report, File No. 1-4473 | | 8/13/1986 | | | | | | | | | | 10.2.2ab | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.2A to APS’s 1993 Form 10-K Report, File No. 1-4473 | | 3/30/1994 | | | | | | | | | | 10.2.2bb | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1 to APS’s September 30, 1994 Form 10-Q Report, File No. 1-4473 | | 11/10/1994 | | | | | | | | | | 10.2.2cb | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.8A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962 | | 3/30/2000 | | | | | | | | | | 10.2.3b | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.14A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962 | | 3/30/2000 | | | | | | | | | | 10.2.3ab | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.15A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962 | | 3/30/2000 | | | | | | | | | | 10.2.4b | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.10A to APS’s 1995 Form 10-K Report, File No. 1-4473 | | 3/29/1996 | | | | | | | | | | 10.2.4ab | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.7A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962 | | 3/30/2000 | | | | | | | | | |
| | | | | | | | | | Exhibit
No.10.2.4bb
| | Registrant(s)Pinnacle West APS | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 10.2.4bb
| | Pinnacle West
APS
| | | | 10.10A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962 | | 3/30/2000 | | | | | | | | | | 10.2.4cb | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962 | | 5/15/2003 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.2.4db | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.64b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 3/13/2006 | | | | | | | | | | 10.2.5b | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.2.5 to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/19/2016 | | | | | | | | | | 10.3.1b | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.7A to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962 | | 3/15/2004 | | | | | | | | | | 10.3.1ab | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.48b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 3/13/2006 | | | | | | | | | | 10.3.2b | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3.2 to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/19/2016 | | | | | | | | | | 10.3.2ab | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3.2a to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2017 | | | | | | | | | | 10.3.2bb | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3.2b to Pinnacle West/APS 2017 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/23/2018 | | | | | | | | | | 10.4.1b | | Pinnacle West APS | | | | 10.1 to Pinnacle West/APS September 30, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 11/7/2019 | | | | | | | | | | 10.4.2b
| | Pinnacle West
APS
| | | | 10.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/7/2008 | | | | | | | | | |
| | | | | | | | | | Exhibit
No.10.4.2b
| | Registrant(s)Pinnacle West APS | | Description | | | | Date Filed10.1 to Pinnacle West/APS August 24, 2021 form 8-K; File Nos. 1-8962 and 1-4473 | | 8/24/2021 | 10.4.3b | | Pinnacle West APS | | | | 10.4.2 to Pinnacle West/APS 2018 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/22/2019 | | | | | | | | | | 10.4.4b
| | APS | | | | 10.4.3 to Pinnacle West/APS 2018 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/22/2019 | | | | | | | | | | 10.4.5b
| | Pinnacle West
APS
| | | | 10.4.5 to Pinnacle West/APS 2019 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/21/2020 | | | | | | | | | | 10.4.610.4.4b
| | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.4.6 to Pinnacle West/APS 2019 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/21/2020 | | | | | | | | | | 10.4.5b | | Pinnacle West APS | | | | 10.4.4 to Pinnacle West/APS 2020 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2021 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.4.6ab | | Pinnacle West APS | | | | 10.4.5a to Pinnacle West/APS 2021 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2021 | 10.4.6bb | | Pinnacle West APS | | | | 10.4.5b to Pinnacle West/APS 2021 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2021 | | | | | | | | | | 10.4.7b | | Pinnacle West APS | | | | 10.4.6 to Pinnacle West/APS 2021 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2021 | | | | | | | | | | 10.4.8b | | Pinnacle West APS | | | | 10.4.7 to Pinnacle West/APS 2021 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2021 | | | | | | | | | | 10.4.9b | | Pinnacle West APS | | | | 10.4.8 to Pinnacle West/APS 2021 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2021 | | | | | | | | | | 10.5.1bd | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.77bd to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 3/13/2006 | | | | | | | | | | 10.5.1abd | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.4 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 11/6/2007 | | | | | | | | | | 10.5.2bd | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 11/6/2007 | | | | | | | | | | 10.5.3bd | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.5.3 to Pinnacle West/APS 2009 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/19/2010 | | | | | | | | | | 10.5.4bd | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.5.4 to Pinnacle West/APS 2012 Form 10-K, File Nos. 1-8962 and 1-4473 | | 2/22/2013 | 10.5.5bd | | Pinnacle West APS | | | | 10.4 to Pinnacle West/APS June 30, 2021 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/5/2021 | | | | | | | | | | 10.6.1b | | Pinnacle West | | | | Appendix B to the Proxy Statement for Pinnacle West’s 2007 Annual Meeting of Shareholders, File No. 1-8962 | | 4/20/2007 | | | | | | | | | | 10.6.1ab | | Pinnacle West | | | | 10.2 to Pinnacle West/APS April 18, 2007 Form 8-K Report, File No. 1-8962 | | 4/20/2007 | | | | | | | | | | 10.6.1bbd | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3 to Pinnacle West/APS March 31, 2009 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/5/2009 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.6.1cbd | | Pinnacle West | | | | 10.1 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962 | | 8/3/2010 | | | | | | | | | | 10.6.1dbd | | Pinnacle West | | | | 10.2 to Pinnacle West/APS June 30, 2010 Form 10-Q Report, File No. 1-8962 | | 8/3/2010 | | | | | | | | | |
| | | | | | | | | | Exhibit
No.10.6.1ebd
| | Registrant(s)Pinnacle West | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 10.6.1ebd
| | Pinnacle West | | | | 10.4 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962 | | 4/29/2011 | | | | | | | | | | 10.6.1fbd | | Pinnacle West | | | | 10.5 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962 | | 4/29/2011 | | | | | | | | | | 10.6.1gbd | | Pinnacle West | | | | 10.6 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File No. 1-8962 | | 4/29/2011 | | | | | | | | | | 10.6.2b | | Pinnacle West | | | | 10.1 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962 | | 11/6/2007 | | | | | | | | | | 10.6.3b | | Pinnacle West | | | | 10.2 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962 | | 8/7/2008 | | | | | | | | | | 10.6.4bd | | Pinnacle West APS | | Pinnacle West
APS
| | | | | | | | | | | | | | | | 10.6.5 | | Pinnacle West | | | | Pinnacle West/APS December 24, 2012 Form 8-K Report, File No. 1-8962 | | 12/26/2012 | | | | | | | | | | 10.6.610.6.5b
| | Pinnacle West APS | | Pinnacle West
APS
| | | | Appendix A to the Proxy Statement for Pinnacle West’s 2012 Annual Meeting of Shareholders, File No. 1-8962 | | 3/29/2012 | | | | | | | | | | 10.6.6a10.6.5abd
| | Pinnacle West | | | | 10.1 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/3/2012 | | | | | | | | | | 10.6.6b10.6.5bbd
| | Pinnacle West | | | | 10.2 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/3/2012 | | | | | | | | | | 10.6.6c10.6.5cbd
| | Pinnacle West | | | | 10.6.8c to Pinnacle West/APS 2013 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/21/2014 | | | | | | | | | | 10.6.6d10.6.5dbd
| | Pinnacle West | | | | 10.6.8d to Pinnacle West/APS 2013 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/21/2014 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.6.6e10.6.5ebd
| | Pinnacle West | | | | 10.6.6e to Pinnacle West/APS 2015 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/19/2016 | | | | | | | | | | 10.6.6f10.6.5fbd
| | Pinnacle West | | | | 10.6.6f to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2017 | | | | | | | | | |
| | | | | | | | | | Exhibit
No.10.6.5gbd
| | Registrant(s)Pinnacle West | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 10.6.6gbd
| | Pinnacle West | | | | 10.6.6g to Pinnacle West/APS 2016 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2017 | | | | | | | | | | 10.6.6h10.6.5hbd
| | Pinnacle West | | | | 10.2 to Pinnacle West/APS March 31, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/1/2019 | | | | | | | | | | 10.6.6i10.6.5ibd
| | Pinnacle West | | | | 10.3 to Pinnacle West/APS March 31, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/1/2019 | | | | | | | | | | 10.6.6j10.6.5jbd
| | Pinnacle West | | | | 10.1 to Pinnacle West/APS March 31, 2020 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/8/2020 | | | | | | | | | | 10.6.5kbd | | Pinnacle West | | | | 10.6.5k to Pinnacle West/APS 2020 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2021 | | | | | | | | | | 10.6.5lbd | | Pinnacle West | | | | 10.6.5l to Pinnacle West/APS 2020 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2021 | 10.6.5mbd | | Pinnacle West APS | | | | Appendix A to the Proxy Statement for Pinnacle West’s 2021 Annual Meeting of Shareholders, File No. 1-8962 | | 4/01/2021 | 10.6.5nbd | | Pinnacle West | | | | | | | 10.6.5obd | | Pinnacle West | | | | | | | 10.6.5pbd | | Pinnacle West | | | | | | | 10.6.5qbd | | Pinnacle West | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.6.5rbd | | Pinnacle West | | | | | | | 10.6.5sbd | | Pinnacle West | | | | | | | | | | | | | | | | 10.6.5tbd | | Pinnacle West | | | | 10.3 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/3/2012 | | | | | | | | | | 10.6.6k10.6.5ubd
| | Pinnacle West | | | | 10.4 to Pinnacle West/APS March 31, 2012 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/3/2012 | | | | | | | | | | 10.6.6l10.6.5vbd
| | Pinnacle West | | | | 10.1 to Pinnacle West/APS June 30, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/2/2017 | | | | | | | | | | 10.6.6mbd
| | Pinnacle West | | | | Appendix A to the Proxy Statement for Pinnacle West’s 2017 Annual Meeting of Shareholders, File No. 1-8962 | | 3/31/2017 | | | | | | | | | | 10.7.1 | | Pinnacle West APS
| | Indenture of Lease with Navajo Tribe of Indians, Four Corners Plant | | 5.01 to APS'sAPS’s Form S-7 Registration Statement, File No. 2-59644 | | 9/1/1977 | | | | | | | | | | 10.7.1a | | Pinnacle West APS
| | Supplemental and Additional Indenture of Lease, including amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant | | 5.02 to APS’s Form S-7 Registration Statement, File No. 2-59644 | | 9/1/1977 | | | | | | | | | | 10.7.1b | | Pinnacle West APS
| | Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease Four Corners, dated April 25, 1985 | | 10.36 to Pinnacle West’s Registration Statement on Form 8-B Report, File No. 1-89 | | 7/25/1985 | | | | | | | | | | 10.7.1c | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 4/29/2011 | | | | | | | | | | 10.7.1d | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.2 to Pinnacle West/APS March 31, 2011 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 4/29/2011 | | | | | | | | | | 10.7.2 | | Pinnacle West APS
| | Application and Grant of multi-party rights-of-way and easements, Four Corners Plant Site | | 5.04 to APS’s Form S-7 Registration Statement, File No. 2-59644 | | 9/1/1977 | | | | | | | | | | 10.7.2a | | Pinnacle West APS
| | Application and Amendment No. 1 to Grant of multi-party rights-of-way and easements, Four Corners Site dated April 25, 1985 | | 10.37 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962 | | 7/25/1985 | | | | | | | | | |
| | | | | | | | | | Exhibit
No. 10.7.3 | | Registrant(s) | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 10.7.3 | | Pinnacle West APS
| | Application and Grant of APS rights- of-way and easements, Four Corners Site | | 5.05 to APS’s Form S-7 Registration Statement, File No. 2-59644 | | 9/1/1977 | | | | | | | | | | 10.7.3a | | Pinnacle West APS
| | Application and Amendment No. 1 to Grant of APS rights-of-way and easements, Four Corners Site dated April 25, 1985 | | 10.38 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962 | | 7/25/1985 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | 10.7.4Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.7.4 | | Pinnacle West APS
| | | | 10.7.4c to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/3/2018 | 10.7.4a | | Pinnacle West APS | | | | 10.5 to Pinnacle West/APS June 30, 2021 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/5/2021 | 10.8.1 | | | | | | | | | 10.8.1 | | Pinnacle West APS
| | Indenture of Lease, Navajo Units 1, 2, and 3 | | 5(g) to APS’s Form S-7 Registration Statement, File No. 2-36505 | | 3/23/1970 | | | | | | | | | | 10.8.2 | | Pinnacle West APS
| | Application of Grant of rights-of-way and easements, Navajo Plant | | 5(h) to APS Form S-7 Registration Statement, File No. 2-36505 | | 3/23/1970 | | | | | | | | | | 10.8.3 | | Pinnacle West APS
| | Water Service Contract Assignment with the United States Department of Interior, Bureau of Reclamation, Navajo Plant | | 5(l) to APS’s Form S-7 Registration Statement, File No. 2-394442 | | 3/16/1971 | | | | | | | | | | 10.8.4 | | Pinnacle West APS | | Pinnacle West
APS
| | Navajo Project Co-Tenancy Agreement dated as of March 23, 1976, and Supplement No. 1 thereto dated as of October 18, 1976, Amendment No. 1 dated as of July 5, 1988, and Amendment No. 2 dated as of June 14, 1996; Amendment No. 3 dated as of February 11, 1997; Amendment No. 4 dated as of January 21, 1997; Amendment No. 5 dated as of January 23, 1998; Amendment No. 6 dated as of July 31, 1998 | | 10.107 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 3/13/2006 | | | | | | | | | | 10.8.5 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.108 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 3/13/2006 | | | | | | | | | | 10.9.1 | | Pinnacle West APS
| | ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto | | 10. 110.1 to APS’s 1988 Form 10-K Report, File No. 1-4473 | | 3/8/1989 | | | | | | | | | |
Exhibit
No.
| | Registrant(s) | | Description | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.9.1a | | Pinnacle West APS
| | Amendment No. 13, dated as of April 22, 1991, to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles | | 10.1 to APS’s March 31, 1991 Form 10-Q Report, File No. 1-4473 | | 5/15/1991 | | | | | | | | | | 10.9.1b | | Pinnacle West APS | | Pinnacle West
APS
| | | | 99.1 to Pinnacle West’s June 30, 2000 Form 10-Q Report, File No. 1-8962 | | 8/14/2000 | | | | | | | | | | 10.9.1c | | Pinnacle West APS | | Pinnacle West
APS
| | Amendment No. 15, dated November 29, 2010, to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles | | 10.9.1c to Pinnacle West/APS 2010 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/18/2011 | | | | | | | | | | 10.9.1d | | Pinnacle West APS | | Pinnacle West
APS
| | Amendment No. 16, dated April 28, 2014, to ANPP Participation Agreement, dated August 23, 1973, among APS, SRP, SCE, Public Service Company of New Mexico, El Paso, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles | | 10.2 to Pinnacle West/APS March 31, 2014 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/2/2014 | | | | | | | | | | 10.10.1 | | Pinnacle West APS
| | Asset Purchase and Power Exchange Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991 | | 10.1 to APS’s June 30, 1991 Form 10-Q Report, File No. 1-4473 | | 8/8/1991 | | | | | | | | | | 10.10.2 | | Pinnacle West APS
| | Long-Term Power Transaction Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990, and as of July 8, 1991 | | 10.2 to APS’s June 30, 1991 Form 10-Q Report, File No. 1-4473 | | 8/8/1991 | | | | | | | | | | 10.10.2a | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3 to APS’s 1995 Form 10-K Report, File No. 1-4473 | | 3/29/1996 | | | | | | | | | | 10.10.3 | | Pinnacle West
APS
| | | | 10.4 to APS’s 1995 Form 10-K Report, File No. 1-4473 | | 3/29/1996 | | | | | | | | | |
| | | | | | | | | | 10.10.3 | | Pinnacle West APS | | Exhibit
| | Registrant(s)10.4 to APS’s 1995 Form 10-K Report, File No. 1-4473 | | Description3/29/1996 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.10.4 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.5 to APS’s 1995 Form 10-K Report, File No. 1-4473 | | 3/29/1996 | | | | | | | | | | 10.10.5 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.6 to APS’s 1995 Form 10-K Report, File No. 1-4473 | | 3/29/1996 | | | | | | | | | | 10.11.1 | | Pinnacle West | | | | 10.4.2 to Pinnacle West/APS 2018 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/22/2019 | | | | | | | | | | 10.11.2 | | Pinnacle West APS | | | | 10.1 to Pinnacle West/APS March 31, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/1/2019 | | | | | | | | | | 10.11.310.11.2 | | Pinnacle West | | | | 10.310.1 to Pinnacle West/APS June 30, 20182021 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/3/20185/2021 | | | | | | | | | | 10.11.410.11.3 | | Pinnacle West APS | | | | 10.1 to Pinnacle West/APS June 30, 2019 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/8/2019 | | | | | | | | | | 10.11.5 | | Pinnacle West
APS
| | | | 10.2 to Pinnacle West/APS June 30, 20172021 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/3/20175/2021 | 10.11.4 | | Pinnacle West APS | | | | | | | 10.11.5a | | Pinnacle West
APS
| | Amendment No. 1, dated July 13, 2018, to Five-Year Credit Agreement dated as of June 29, 2017,May 28, 2021, among APS, as Borrower, Barclays Bank PLC, as Agent, Co-Sustainability Structuring Agent and Issuing Bank, and the lenders and other parties thereto | | 10.11.4a10.3 to Pinnacle West/APS June 30, 20182021 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/3/2018 | | | | | | | | | |
5/2021 | | | | | | | | | | Exhibit
No.
| | Registrant(s) | | Description | | Previously Filed as Exhibit: 10.12.1ac
| | Date Filed | 10.11.6 | | Pinnacle West APS
| |
| | 10.4 to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/3/2018 | | | | | | | | | | 10.12.1c
| | Pinnacle West
APS
| | Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee | | 4.3 to APS’s Form 18 Registration Statement, File No. 33-9480 | | 10/24/1986 | | | | | | | | | | 10.12.1ac | | Pinnacle West APS
| | Amendment No. 1, dated as of November 1, 1986, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee | | 10.5 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473 | | 12/4/1986 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.12.1bc | | Pinnacle West APS
| | Amendment No. 2 dated as of June 1, 1987 to Facility Lease dated as of August 1, 1986 between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee | | 10.3 to APS’s 1988 Form 10-K Report, File No. 1-4473 | | 3/8/1989 | | | | | | | | | | 10.12.1cc | | Pinnacle West APS
| | Amendment No. 3, dated as of March 17, 1993, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee | | 10.3 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 10.12.1dc | | Pinnacle West APS | | Pinnacle West
APS
| | Amendment No. 4, dated as of September 30, 2015, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under a Trust Agreement with Emerson Finance LLC, as Lessor, and APS, as Lessee | | 10.2 to Pinnacle West/APS September 30, 2015 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 10/30/2015 | | | | | | | | | |
| | | | | | | | | | Exhibit
No.10.12.1ec
| | Registrant(s)Pinnacle West APS | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 10.12.1ec
| | Pinnacle West
APS
| | Amendment No. 3, dated as of September 30, 2015, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under a Trust Agreement with Security Pacific Capital Leasing Corporation, as Lessor, and APS, as Lessee | | 10.3 to Pinnacle West/APS September 30, 2015 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 10/30/2015 | | | | | | | | | | 10.12.2 | | Pinnacle West APS
| | Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee | | 10.1 to APS’s November 18, 1986 Form 8-K Report, File No. 1-4473 | | 1/20/1987 | | | | | | | | | | 10.12.2a | | Pinnacle West APS
| | Amendment No. 1, dated as of August 1, 1987, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee | | 4.13 to APS’s Form 18 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473 | | 8/24/1987 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | 10.12.2bExhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.12.2b | | Pinnacle West APS
| | Amendment No. 2, dated as of March 17, 1993, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee | | 10.4 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 10.12.2c | | Pinnacle West APS | | Pinnacle West
APS
| | Amendment No. 3, dated July 10, 2014, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to the First National Bank of Boston, as Lessor, and APS, as Lessee | | 10.2 to Pinnacle West/APS June 30, 2014 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 7/31/2014 | 10.12.2d | | Pinnacle West APS | | Amendment No. 4, dated April 1, 2021, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to the First National Bank of Boston, as Lessor, and APS, as Lessee | | 10.1 to Pinnacle West/APS March 31, 2021 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/5/2021 | 10.13.1 | | | | | | | | | 10.13.1 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.102 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 3/16/2005 | | | | | | | | | | 10.13.2 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.103 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 3/16/2005 | | | | | | | | | |
| | | | | | | | | | Exhibit
No. 10.13.3 | | Registrant(s)Pinnacle West APS | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 10.13.3 | | Pinnacle West
APS
| | | | 10.104 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 3/16/2005 | | | | | | | | | | 10.13.4 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.105 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 3/16/2005 | | | | | | | | | | 10.13.5 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1 to Pinnacle West/APS March 31, 2010 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/6/2010 | | | | | | | | | | 10.14.1 | | Pinnacle West APS
| | Contract, dated July 21, 1984, with DOE providing for the disposal of nuclear fuel and/or high-level radioactive waste, ANPP | | 10.31 to Pinnacle West’s Form S-14 Registration Statement, File No. 2-96386 | | 3/13/1985 | | | | | | | | | | 10.15.1 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473 | | 5/15/1998 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | 10.15.2Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 10.15.2 | | Pinnacle West APS
| | | | 10.2 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473 | | 5/15/1998 | | | | | | | | | | 10.15.3 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.3 to APS’s March 31, 1998 Form 10-Q Report, File No. 1-4473 | | 5/15/1998 | | | | | | | | | | 10.15.3a | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.2 to APS’s May 19, 1998 Form 8-K Report, File No. 1-4473 | | 6/26/1998 | | | | | | | | | | 10.16 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1 to Pinnacle West/APS November 8, 2010 Form 8-K Report, File Nos. 1-8962 and 1-4473 | | 11/8/2010 | | | | | | | | | | 10.17 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.17 to Pinnacle West/APS 2011 Form 10-K Report, File Nos. 1-8962 and 1-4473 | | 2/24/2012 | | | | | | | | | | 10.18 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.1 to Pinnacle West/APS March 31, 2017 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 5/2/2017 | | | | | | | | | | 10.19 | | Pinnacle West | | | | 10.2 to Pinnacle West/APS June 30, 2018 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/3/2018 | | | | | | | | | | 21.1 | | Pinnacle West | | | | | | | | | | | | | | | | 23.1 | | Pinnacle West | | | | | | | | | | | | | | | | 23.2 | | APS | | | | | | | | | | | | | | | | 31.1 | | Pinnacle West | | | | | | |
| | | | | | | | | | Exhibit
No. 31.2 | | Registrant(s)Pinnacle West | | Description | | Previously Filed as Exhibit: a
| | Date Filed | | | | | | | | | | 31.2 | | Pinnacle West | | | | | | | | | | | | | | | | 31.3 | | APS | | | | | | | | | | | | | | | | 31.4 | | APS | | | | | | | | | | | | | | | | 32.1e | | Pinnacle West | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 32.2e | | APS | | | | | | | | | | | | | | | | 99.1 | | Pinnacle West
APS
| | Collateral Trust Indenture among PVGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee | | 4.2 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 99.1a | | Pinnacle West
APS
| | Supplemental Indenture to Collateral Trust Indenture among PVGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee | | 4.3 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 99.299.1c
| | Pinnacle West APS
| | Participation Agreement, dated as of August 1, 1986, among PVGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein | | 28.1 to APS’s September 30, 1992 Form 10-Q Report, File No. 1-4473 | | 11/9/1992 | | | | | | | | | | 99.2a99.1ac
| | Pinnacle West APS
| | Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1, 1986, among PVGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein | | 10.8 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8, File No. 1-4473 | | 12/4/1986 | | | | | | | | | |
| | | | | | | | | | Exhibit
No.
| | Registrant(s) | | Description | | Previously Filed as Exhibit: 99.1bac
| | Date Filed | 99.2bc
| | Pinnacle West APS
| | Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of August 1, 1986, among PVGS Funding Corp., Inc., PVGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein | | 28.4 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 99.399.2c
| | Pinnacle West APS
| | Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee | | 4.5 to APS’s Form 18 Registration Statement, File No. 33-9480 | | 10/24/1986 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | Exhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 99.3a99.2ac
| | Pinnacle West APS
| | Supplemental Indenture No. 1, dated as of November 1, 1986 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee | | 10.6 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473 | | 12/4/1986 | | | | | | | | | | 99.3b99.2bc
| | Pinnacle West APS
| | Supplemental Indenture No. 2 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee | | 4.4 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 99.499.3c
| | Pinnacle West APS
| | Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee | | 28.3 to APS’s Form 18 Registration Statement, File No. 33-9480 | | 10/24/1986 | | | | | | | | | | 99.4a99.3ac
| | Pinnacle West APS
| | Amendment No. 1, dated as of November 1, 1986, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee | | 10.10 to APS’s September 30, 1986 Form 10-Q Report by means of Amendment No. l on December 3, 1986 Form 8, File No. 1-4473 | | 12/4/1986 | | | | | | | | | |
| | | | | | | | | | Exhibit
No.
| | Registrant(s) | | Description | | Previously Filed as Exhibit: 99.3bac
| | Date Filed | 99.4bc
| | Pinnacle West APS
| | Amendment No. 2, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee | | 28.6 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 99.599.4 | | Pinnacle West APS
| | Participation Agreement, dated as of December 15, 1986, among PVGS Funding Report Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, APS, and the Owner Participant named therein | | 28.2 to APS’s September 30, 1992 Form 10-Q Report, File No. 1-4473 | | 11/9/1992 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | 99.5aExhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 99.4a | | Pinnacle West APS
| | Amendment No. 1, dated as of August 1, 1987, to Participation Agreement, dated as of December 15, 1986, among PVGS Funding Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, APS, and the Owner Participant named therein | | 28.20 to APS’s Form 18 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473 | | 8/10/1987 | | | | | | | | | | 99.5b99.4b | | Pinnacle West APS
| | Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of December 15, 1986, among PVGS Funding Corp., Inc., PVGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Owner Participant named therein | | 28.5 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 99.699.5 | | Pinnacle West APS
| | Trust Indenture, Mortgage Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee | | 10.2 to APS’s November 18, 1986 Form 10-K Report, File No. 1-4473 | | 1/20/1987 | | | | | | | | | | 99.6a99.5a | | Pinnacle West APS
| | Supplemental Indenture No. 1, dated as of August 1, 1987, to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee | | 4.13 to APS’s Form 18 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473 | | 8/24/1987 | | | | | | | | | |
| | | | | | | | | | Exhibit
No. 99.5b | | Registrant(s) | | Description | | Previously Filed as Exhibit: a
| | Date Filed | 99.6b | | Pinnacle West APS
| | Supplemental Indenture No. 2 to Trust Indenture Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee | | 4.5 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 99.799.6 | | Pinnacle West APS
| | Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee | | 10.5 to APS’s November 18, 1986 Form 8-K Report, File No. 1-4473 | | 1/20/1987 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | 99.7aExhibit No. | | Registrant(s) | | Description | | Previously Filed as Exhibit: a | | Date Filed | 99.6a | | Pinnacle West APS
| | Amendment No. 1, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee | | 28.7 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 99.899.7c
| | Pinnacle West APS
| | Indemnity Agreement dated as of March 17, 1993 by APS | | 28.3 to APS’s 1992 Form 10-K Report, File No. 1-4473 | | 3/30/1993 | | | | | | | | | | 99.999.8 | | Pinnacle West APS
| | Extension Letter, dated as of August 13, 1987, from the signatories of the Participation Agreement to Chemical Bank | | 28.20 to APS’s Form 18 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473 | | 8/10/1987 | | | | | | | | | | 99.1099.9 | | Pinnacle West APS | | Pinnacle West
APS
| | | | 10.2 to APS’s September 30, 1999 Form 10-Q Report, File No. 1-4473 | | 11/15/1999 | | | | | | | | | | 99.1199.10 | | Pinnacle West | | | | 99.5 to Pinnacle West/APS June 30, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473 | | 8/9/2005 | | | | | | | | | | 101.SCH | | Pinnacle West APS
| | XBRL Taxonomy Extension Schema Document | | | | | | | | | | | | | | 101.CAL | | Pinnacle West APS
| | XBRL Taxonomy Extension Calculation Linkbase Document | | | | | | | | | | | | | | 101.LAB | | Pinnacle West APS
| | XBRL Taxonomy Extension Label Linkbase Document | | | | | | | | | | | | | | 101.PRE | | Pinnacle West APS
| | XBRL Taxonomy Extension Presentation Linkbase Document | | | | | | | | | | | | | | 101.DEF | | Pinnacle West APS
| | XBRL Taxonomy Definition Linkbase Document | | | | |
aReports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange CommissionSEC located in Washington, D.C.
bManagement contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 15(b) of Form 10-K. cAn additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit. dAdditional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit. eFurnished herewith as an Exhibit.
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | | | | PINNACLE WEST CAPITAL CORPORATION | | (Registrant) | | | | | | PINNACLE WEST CAPITAL CORPORATION | | (Registrant) | | | | | Date: February 21, 202025, 2022 | /s/ Jeffrey B. Guldner | | (Jeffrey B. Guldner, Chairman of the Board of Directors, President and
Chief Executive Officer)
|
Power of Attorney We, the undersigned directors and executive officers of Pinnacle West Capital Corporation, hereby severally appoint Theodore N. Geisler and Robert E. Smith, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. | | | | | | | | | | | | | | | Signature | | Title | | Date | | | | | | | | | | | Signature | | Title | | Date | | | | | | | | | | | /s/ Jeffrey B. Guldner | | Principal Executive Officer | | February 21, 202025, 2022 | (Jeffrey B. Guldner, Chairman | | and Director | | | of the Board of Directors, President | | | | | and Chief Executive Officer) | | | | | | | | | | | | | | | /s/ Theodore N. Geisler | | Principal Financial Officer | | February 21, 2020 | (Theodore N. Geisler, | | | | | Senior Vice President and | | | | | Chief Financial Officer) | | | | | | | | | | | | | | | /s/ Elizabeth A. Blankenship | | Principal Accounting Officer | | February 21, 2020 | (Elizabeth A. Blankenship, | | | | | Vice President, Controller and | | | | | Chief Accounting Officer) | | | | |
| | | | | | | | | | | /s/ Theodore N. Geisler | | Principal Financial Officer | | February 25, 2022 | (Theodore N. Geisler, | | | | | Senior Vice President and | | | | | Chief Financial Officer) | | | | | | | | | | | | | | | /s/ Elizabeth A. Blankenship | | Principal Accounting Officer | | February 25, 2022 | (Elizabeth A. Blankenship, | | | | | Vice President, Controller and | | | | | Chief Accounting Officer) | | | | |
| | | | | | | | | | | | | | | | | | | | /s/ Glynis A. Bryan | | Director | | February 25, 2022 | (Glynis A. Bryan) | | | | | | | | | | | | | | | /s/ Denis A. Cortese, M.D. | | Director | | February 21, 202025, 2022 | (Denis A. Cortese, M.D.) | | | | | | | | | | | | | | | /s/ Richard P. Fox | | Director | | February 21, 202025, 2022 | (Richard P. Fox) | | | | | | | | | | | | | | | /s/ Michael L. Gallagher | | Director | | February 21, 2020 | (Michael L. Gallagher) | | | | | | | | | | | | | | | /s/ Dale E. Klein, Ph.D. | | Director | | February 21, 202025, 2022 | (Dale E. Klein, Ph.D.) | | | | | | | | | | | | | | | /s/ Humberto S. Lopez | | Director | | February 21, 2020 | (Humberto S. Lopez) | | | | | | | | | | | | | | | /s/ Kathryn L. Munro | | Director | | February 21, 202025, 2022 | (Kathryn L. Munro) | | | | | | | | | | | | | | | /s/ Bruce J. Nordstrom | | Director | | February 21, 202025, 2022 | (Bruce J. Nordstrom) | | | | | | | | | | | | | | | /s/ Paula J. Sims | | Director | | February 21, 202025, 2022 | (Paula J. Sims) | | | | | | | | | | | | | | | /s/ William H. Spence | | Director | | February 25, 2022 | (William H. Spence) | | | | | | | | | | | | | | | /s/ James E. Trevathan, Jr. | | Director | | February 21, 202025, 2022 | (James E. Trevathan)Trevathan, Jr.) | | | | | | | | | | | | | | | /s/ David P. Wagener | | Director | | February 21, 202025, 2022 | (David P. Wagener) | | | | | | | | | |
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | | | | ARIZONA PUBLIC SERVICE COMPANY | | (Registrant) | | | | | Date: February 21, 202025, 2022 | /s/ Jeffrey B. Guldner | | (Jeffrey B. Guldner, Chairman of the Board of Directors, President and
Chief Executive Officer)
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Power of Attorney We, the undersigned directors and executive officers of Arizona Public Service Company, hereby severally appoint Theodore N. Geisler and Robert E. Smith, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. | | | | | | | | | | | | | | | Signature | | Title | | Date | | | | | | | | | | | /s/ Jeffrey B. Guldner | | Principal Executive Officer | | February 25, 2022 | (Jeffrey B. Guldner, Chairman | | and Director | | | of the Board of Directors, President and | | | | | Chief Executive Officer) | | | | | | | | | | | | | | | /s/ Theodore N. Geisler | | Principal Financial Officer | | February 25, 2022 | (Theodore N. Geisler, | | | | | Senior Vice President and | | | | | Chief Financial Officer) | | | | | | | | | | | | | | | /s/ Elizabeth A. Blankenship | | Principal Accounting Officer | | February 25, 2022 | (Elizabeth A. Blankenship | | | | | Vice President, Controller and | | | | | Chief Accounting Officer) | | | | |
| | | | | | | | | | | | | | | | | | | | Signature/s/ Glynis A. Bryan | | TitleDirector | | DateFebruary 25, 2022 | (Glynis A. Bryan) | | | | | | | | | | /s/ Jeffrey B. Guldner | | Principal Executive Officer | | February 21, 2020 | (Jeffrey B. Guldner, Chairman | | and Director | | | of the Board of Directors and | | | | | Chief Executive Officer) | | | | | | | | | | | | | | | /s/ Theodore N. Geisler | | Principal Financial Officer | | February 21, 2020 | (Theodore N. Geisler, | | | | | Senior Vice President and | | | | | Chief Financial Officer) | | | | | | | | | | | | | | | /s/ Elizabeth A. Blankenship | | Principal Accounting Officer | | February 21, 2020 | (Elizabeth A. Blankenship | | | | | Vice President, Controller and | | | | | Chief Accounting Officer) | | | | |
| | | | | | | | | | | /s/ Denis A. Cortese, M.D. | | Director | | February 21, 202025, 2022 | (Denis A. Cortese, M.D.) | | | | | | | | | | | | | | | /s/ Richard P. Fox | | Director | | February 21, 202025, 2022 | (Richard P. Fox) | | | | | | | | | | | | | | | /s/ Michael L. Gallagher | | Director | | February 21, 2020 | (Michael L. Gallagher) | | | | | | | | | | | | | | | /s/ Dale E. Klein Ph.D. | | Director | | February 21, 202025, 2022 | (Dale E. Klein, Ph.D.) | | | | | | | | | | | | | | | /s/ Humberto S. Lopez | | Director | | February 21, 2020 | (Humberto S. Lopez) | | | | | | | | | | | | | | | /s/ Kathryn L. Munro | | Director | | February 21, 202025, 2022 | (Kathryn L. Munro) | | | | | | | | | | | | | | | /s/ Bruce J. Nordstrom | | Director | | February 21, 202025, 2022 | (Bruce J. Nordstrom) | | | | | | | | | | | | | | | /s/ Paula J. Sims | | Director | | February 21, 202025, 2022 | (Paula J. Sims) | | | | | | | | | | | | | | | /s/ William H. Spence | | Director | | February 25, 2022 | (William H. Spence) | | | | | | | | | | | | Director | | February 25, 2022 | /s/ James E. Trevathan, Jr. | | Director | | February 21, 2020 | (James E. Trevathan)Trevathan, Jr.) | | | | | | | | | | | | | | | /s/ David P. Wagener | | Director | | February 21, 202025, 2022 | (David P. Wagener) | | | | | | | | | |
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