Stock compensation cumulative effect adjustments

^[1]

$ 45,855

$ 40,380

$ 5,475

Beginning balance at Dec. 31, 2015

4,719,457

$ 2,541,668

$ (5,806)

2,092,803

$ (44,748)

$ 135,540

$ 4,814,794

$ 178,162

$ 2,379,696

$ 2,148,493

$ (27,097)

$ 135,540

Beginning Balance (in shares) at Dec. 31, 2015

111,095,402

115,030

71,264,947

Other comprehensive income (loss)

Net income

461,527

442,034

19,493

481,634

462,141

19,493

926

1,674

Dividends on common stock

(284,765)

(284,800)

Issuance of common stock

13,982

$ 13,982

Issuance of common stock (in shares)

296,651

Purchase of treasury stock

^[2]

(9,087)

$ (9,087)

Purchase of treasury stock (in shares)

^[2]

(128,105)

Reissuance of treasury stock for stock-based compensation and other

10,760

$ 10,760

Reissuance of treasury stock for stock-based compensation and other (in shares)

187,818

Equity infusion from Pinnacle West

42,000

Net capital activities by noncontrolling interests

(22,743)

Ending balance at Dec. 31, 2016

4,935,912

$ 2,596,030

$ (4,133)

2,255,547

(43,822)

132,290

5,037,970

$ 178,162

2,421,696

2,331,245

(25,423)

132,290

Ending Balance (in shares) at Dec. 31, 2016

111,392,053

55,317

71,264,947

Stock compensation cumulative effect adjustments

^[3]

5,411

Net income

507,949

488,456

19,493

523,802

504,309

19,493

Other comprehensive income (loss)

(1,180)

(1,560)

Dividends on common stock

(301,492)

(301,600)

Issuance of common stock

18,775

$ 18,775

Issuance of common stock (in shares)

424,117

Purchase of treasury stock

^[2]

(17,755)

$ (17,755)

Purchase of treasury stock (in shares)

^[2]

(216,911)

Reissuance of treasury stock for stock-based compensation and other

16,264

$ 16,264

Reissuance of treasury stock for stock-based compensation and other (in shares)

207,765

Equity infusion from Pinnacle West

150,000

Net capital activities by noncontrolling interests

(22,743)

Ending balance at Dec. 31, 2017

$ 5,135,730

$ 2,614,805

$ (5,624)

2,442,511

(45,002)

129,040

5,385,869

$ 178,162

2,571,696

2,533,954

(26,983)

129,040

Ending Balance (in shares) at Dec. 31, 2017

111,816,170

64,463

71,264,947

Other comprehensive income (loss)

Net income

$ 530,540

511,047

19,493

589,758

570,265

19,493

5,846

4,914

Dividends on common stock

(320,927)

(321,001)

Issuance of common stock

19,460

$ 19,460

Issuance of common stock (in shares)

343,726

Purchase of treasury stock

^[2]

(10,338)

$ (10,338)

Purchase of treasury stock (in shares)

^[2]

(129,903)

Reissuance of treasury stock for stock-based compensation and other

11,137

$ 11,137

Reissuance of treasury stock for stock-based compensation and other (in shares)

136,231

Equity infusion from Pinnacle West

150,000

Net capital activities by noncontrolling interests

(22,743)

Reclassification of income tax effects related to new tax reform (See Note 2)

(8,552)

8,552

(8,552)

(5,038)

5,038

(5,038)

Ending balance at Dec. 31, 2018

$ 5,348,705

$ 2,634,265

$ (4,825)

$ 2,641,183

$ (47,708)

$ 125,790

$ 5,786,797

$ 178,162

$ 2,721,696

$ 2,788,256

$ (27,107)

$ 125,790

Ending Balance (in shares) at Dec. 31, 2018

112,159,896

58,135

71,264,947

[1]	During 2016, we adopted new stock-based compensation accounting guidance.
[2]	Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
[3]	During 2016, we adopted new stock-based compensation accounting guidance.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Stockholders' Equity [Abstract]
Common stock dividends declared (in dollars per share)	$ 2.87	$ 2.70	$ 2.56

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

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's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. See Note 10 for more information on 4CA matters.

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

We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 18).

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.

These consolidated financial statements and notes have been prepared consistently, with the exception of the reclassification of certain prior year amounts on our Consolidated Statements of Income and APS's Consolidated Statements of Income. Beginning in the quarter ended March 31, 2018, APS changed the format of presentation of its Consolidated Statements of Income from a utility ratemaking format to a commercial format. Minor changes were made in the description of certain income statement line items and the amounts presented in the comparable prior period also changed by immaterial amounts due to the change from a utility to a non-utility format and also from the adoption of the new accounting guidance for net periodic pension cost and net periodic postretirement benefit cost. In addition, the prior year amounts were reclassified to conform to the current year presentation for the other special use funds in the investment and other assets section on the Consolidated Balance Sheets.

Accounting Records and Use of Estimates

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

Regulatory Accounting

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

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or 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.

See Note 3 for additional information.

Electric Revenues

We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. 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 Native Load customers is based on the reading of their meters. We obtain customers' meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed. 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.

On January 1, 2018, we adopted new revenue guidance ASU 2014-09, Revenue from contracts with customers, accordingly our 2018 electric revenues primarily consist of activities that now 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 invoice practical expedient and, as such, we recognize revenue based on the amount to which we have a right to invoice for services performed. See Note 2.

Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase electricity are netted against other contracts to sell electricity. This is called a "book-out" and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which

power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

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

See Notes 2 and 20 for additional information.

Allowance for Doubtful Accounts

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

Property, Plant and Equipment

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


•	material and labor;


•	contractor costs;


•	capitalized leases;


•	construction overhead costs (where applicable); and


•	allowance for funds used during construction.

Pinnacle West’s property, plant and equipment included in the December 31, 2018 and 2017 Consolidated Balance Sheets is composed of the following (dollars in thousands):



Property, Plant and Equipment:	2018			2017
Generation	$	8,285,514		$	7,963,998
Transmission	3,033,579			2,836,578
Distribution	6,378,345			6,025,856
General plant	1,039,190			971,629
Plant in service and held for future use	18,736,628			17,798,061
Accumulated depreciation and amortization	(6,366,014		)	(6,128,535		)
Net	12,370,614			11,669,526
Construction work in progress	1,170,062			1,291,498
Palo Verde sale leaseback, net of accumulated depreciation	105,775			109,645
Intangible assets, net of accumulated amortization	262,902			257,189
Nuclear fuel, net of accumulated amortization	120,217			117,408
Total property, plant and equipment	$	14,029,570		$	13,445,266

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 11.

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

We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2018 were as follows:

•Fossil plant — 17 years;

•Nuclear plant — 23 years;

•Other generation — 19 years;

•Transmission — 39 years;

•Distribution — 34 years; and

•General plant — 6 years.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $486 million in 2018, $453 million in 2017, and $422 million in 2016. For the years 2016 through 2018, the depreciation rates ranged from a low of 0.18% to a high of 19.67%. The weighted-average depreciation rate was 2.81% in 2018, 2.80% in 2017, and 2.66% in 2016.

Asset Retirement Obligations

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

See Note 11 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 7.03% for 2018, 6.68% for 2017, and 7.17% for 2016. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

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 6).

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 13 for additional information about fair value measurements.

Derivative Accounting

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

We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. See Notes 2 and 16 for additional information about our derivative instruments.

Loss Contingencies and Environmental Liabilities

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

Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries. We also sponsor another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. See Note 7 for additional information on pension and other postretirement benefits. On January 1, 2018, we adopted new accounting guidance ASU 2017-07, Compensation-Retirement Benefits: Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost. See Note 2 for additional discussion.

Nuclear Fuel

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

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero. In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred

claims and an offsetting regulatory liability through the settlement period ending December of 2019. See Note 10 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. On January 1, 2018, we adopted new guidance ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of certain tax effects from accumulated other comprehensive income. See Note 4 for additional discussion.

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,
	2018		2017		2016
Cash paid during the period for:
Income taxes, net of refunds	$	21,173	$	2,186	$	9,956
Interest, net of amounts capitalized	208,479		189,288		184,462
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	132,620	$	130,404	$	114,855
Dividends declared but not paid	82,675		77,667		72,926
Sale of 4CA 7% interest in Four Corners	68,907		—		—

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS's software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $68 million in 2018, $72 million in 2017, and $58 million in 2016. Estimated amortization expense on existing intangible assets over the next five years is $58 million in 2019, $47 million in 2020, $34 million in 2021, $25 million in 2022, and $22 million in 2023. At December 31, 2018, the weighted-average remaining amortization period for intangible assets was 8 years.

Investments

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

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 trust fund, coal reclamation escrow and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 13 and 19 for more information on these investments.

On January 1, 2018, we adopted new accounting guidance ASU 2016-01, Financial Instruments: Recognition and measurement. See Note 2.

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, 2018, 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.

New Accounting Standards	12 Months Ended
New Accounting Standards	Dec. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Standards	New Accounting Standards Standards Adopted in 2018 ASU 2014-09, Revenue from Contracts with Customers In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, became effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application. We adopted this standard and related amendments on January 1, 2018 using the modified retrospective transition approach. The adoption of the new revenue guidance resulted in expanded disclosures, but otherwise did not have a material impact on our financial statements. See Note 20. ASU 2016-01, Financial Instruments: Recognition and Measurement In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance requires certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard was effective for us on January 1, 2018. The standard required modified retrospective application, with the exception of certain aspects of the standard that required prospective application. We adopted this standard on January 1, 2018, using primarily a retrospective approach. Due to regulatory accounting treatment, the adoption of this standard did not have a material impact on our financial statements. See Notes 13 and 19 for disclosures relating to our investments in debt and equity securities. ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate-owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard was effective for us, and was adopted on January 1, 2018, using a retrospective transition method. The adoption of this guidance did not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard. ASU 2016-18, Statement of Cash Flows: Restricted Cash In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and was adopted on January 1, 2018, using a retrospective transition method. The adoption of this guidance did not impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents at transition and in prior periods are insignificant. ASU 2017-01, Business Combinations: Clarifying the Definition of a Business In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting, including acquisitions, disposals, goodwill, and consolidation. The new standard was effective for us and was adopted on January 1, 2018 using a prospective transition approach. This standard did not have an impact on our financial statements on the date of adoption. ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard was effective for us, and was adopted on January 1, 2018, using a modified retrospective transition approach. This standard did not have a significant impact on our financial statements on the date of adoption. On July 3, 2018, 4CA sold its 7% interest in Four Corners. The sale transaction was accounted for in accordance with the guidance in ASU 2017-05, see Note 10. ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component is eligible for presentation as an operating income item, and all other cost components are now presented as non-operating items. This presentation change was applied retrospectively. Furthermore, the new standard allows only the service cost component to be eligible for capitalization. The change in capitalization requirements was applied prospectively. The new guidance was effective for us on January 1, 2018. We adopted this new accounting standard on January 1, 2018. As a result of adopting this standard we have presented the non-service cost components of net benefits costs in other income instead of operating income. Prior year non-service cost components have also been reclassified to conform to this new presentation. We elected to apply the practical expedient guidance. As such, prior period costs have been estimated based on amounts previously disclosed in our pension and other postretirement benefit plan notes. The changes impacting capitalization have been adopted prospectively. As such, upon adoption, we are no longer capitalizing a portion of the non-service cost components of net benefit costs. In 2018 the non-service credit components are a reduction to total benefit costs. Excluding non-service credits from eligible capitalization costs resulted in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income for the year. See Note 7 for additional information related to our pension plans and other postretirement benefits. ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Act was recognized. We early adopted this guidance in the quarter ended March 31, 2018, and we have elected to reclassify the income tax effects of the Tax Act related to other comprehensive income to retained earnings. As of December 31, 2018, on a consolidated basis our accumulated other comprehensive income decreased $9 million, and APS's accumulated other comprehensive income decreased $5 million, as a result of adopting this guidance. Amounts were reclassified from accumulated other comprehensive income to retained earnings, and related to tax rate changes. The adoption of this guidance did not impact our income from continuing operations. See Note 4 for additional discussion of the Tax Act. Standards Adopted in 2019 ASU 2016-02, Leases In February 2016, a new lease accounting standard was issued. This new standard supersedes the existing lease accounting model, and modifies both lessee and lessor accounting. The new standard requires a lessee to reflect most operating lease arrangements on the balance sheet by recording a right-of-use asset and a lease liability that is initially measured at the present value of lease payments. Among other changes, the new standard also modifies the definition of a lease, and requires expanded lease disclosures. Since the issuance of the new lease standard, additional lease related guidance has been issued relating to land easements and how entities may elect to account for these arrangements at transition, among other items. The new lease standard and related amendments were effective for us on January 1, 2019, with early application permitted. The standard must be adopted using a modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings determined at either the date of adoption, or the earliest period presented in the financial statements. The standard includes various optional practical expedients provided to facilitate transition. We adopted this standard, and related amendments, on January 1, 2019. We elected the transition method that allows us to apply the guidance on the date of adoption, January 1, 2019, and will not retrospectively adjust prior periods. We also elected certain transition practical expedients that allow us to not reassess (a) whether any expired or existing contracts are or contain leases, (b) the lease classification for any expired or existing leases and (c) initial direct costs for any existing leases. These practical expedients apply to leases that commenced prior to January 1, 2019. Furthermore, we elected the practical expedient transition provisions relating to the treatment of existing land easements. On January 1, 2019 the adoption of this new accounting standard resulted in the recognition on our Consolidated Balance Sheets of approximately $194 million of right-of-use lease assets and $119 million of lease liabilities relating to our operating lease arrangements. The right-of-use lease assets include $85 million of prepaid lease costs that have been reclassified from other deferred debits, and $10 million of deferred lease costs that have been reclassified from other current liabilities. In addition to these balance sheet impacts the adoption of the guidance will also result in expanded lease related disclosures in our 2019 financial statements. ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard became effective for us on January 1, 2019, with early application permitted. At transition, the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We adopted this standard on January 1, 2019 and because we are not currently applying hedge accounting, the adoption of the standard did not impact our financial statements. Standards Pending Adoption ASU 2016-13, Financial Instruments: Measurement of Credit Losses In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require 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. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements. 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 is effective for us on January 1, 2020, with early application permitted, and may be applied using either a retrospective or prospective transition approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

Regulatory Matters

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Regulatory Matters

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 of $165.9 million. This amount excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%).

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

Other key provisions of the agreement include the following:


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


•	an authorized return on common equity of 10.0%;


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


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


•	a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("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 battery storage costs;


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


•	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


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

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

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

On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated, and APS requested and was granted intervention. Mr. Woodward filed his opening brief on March 28, 2018. The ACC and APS filed responsive briefs on June 21, 2018. The Arizona Court of Appeals issued a Memorandum Decision on December 11, 2018 affirming the ACC decisions challenged by Mr. Woodward. Mr. Woodward filed a petition for review with the Arizona Supreme Court on January 9, 2019. Review by the Arizona Supreme Court is discretionary. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact on our financial position, results of operations or cash flows.

On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”) and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public

service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The complainant requested that the ACC hold a hearing on the amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS,) and, if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing. The ACC held a hearing on this matter beginning in September 2018 and the hearing was concluded on October 1, 2018. Post-hearing briefing was concluded on December 14, 2018. APS expects a recommended opinion and order from the judge within the first quarter of 2019. APS cannot predict the outcome of this matter.

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 January 9, 2019, the ACC Commissioners voted to open a docket for this matter. APS does not believe that the rate review will have a material impact on our financial position, results of operations or cash flows. However, depending upon the results of the rate review, the ACC may take further actions, including potentially attempting to reopen the 2017 Rate Case Decision. APS cannot predict the outcome of this matter.

Prior Rate Case Filing with the Arizona Corporation Commission

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million. On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the "2012 Settlement Agreement") detailing the terms upon which the parties agreed to settle the rate case. On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.

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 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have

complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015.

In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid. The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016. The costs for this program have been included in APS's rate base as part of the 2017 Rate Case Decision.

On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement. On August 15, 2017, the ACC approved the 2017 RES Implementation Plan.

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 is 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, buildings of 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 carrying costs for this program will be recovered through the RES. On June 12, 2018, the ACC approved the 2018 RES Implementation Plan.

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. The ACC has not yet ruled on the 2019 RES Implementation Plan.

In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. On January 30, 2018, ACC Commissioner Tobin proposed a plan in this proceeding which would broaden the RES to include a series of energy policies tied to clean energy sources (the "Energy Modernization Plan"). The Energy Modernization Plan includes replacing the current RES standard with a new standard called the Clean Resource Energy Standard and Tariff ("CREST"), which incorporates the

proposals in the Energy Modernization Plan. A set of draft CREST rules for the ACC’s consideration was issued by Commissioner Tobin’s office on July 5, 2018. See "Energy Modernization Plan" below for more information on CREST.

Demand Side Management Adjustor Charge. The ACC EES requires APS to submit a Demand Side Management Implementation Plan ("DSM Plan") annually for review by and approval of the ACC. On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also ruled that verified energy savings from APS's resource savings projects could be counted toward compliance with the EES; however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from conservation voltage reduction in the calculation of its LFCR mechanism.

On June 1, 2016, APS filed its 2017 DSM Plan, in which APS proposed programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand. The requested budget in the 2017 DSM Plan was $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and requested that the budget be increased to $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Plan.

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

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

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


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


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


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


•	The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year

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


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

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2018 and 2017 (dollars in thousands):



	Twelve Months Ended December 31,
	2018			2017
Beginning balance	$	75,637		$	12,465
Deferred fuel and purchased power costs — current period	78,277			48,405
Amounts refunded/(charged) to customers	(116,750		)	14,767
Ending balance	$	37,164		$	75,637

The PSA rate for the PSA year beginning February 1, 2017 was $(0.001348) per kWh, as compared to $0.001678 per kWh for the prior year. This rate was comprised of a forward component of $(0.001027) per kWh and a historical component of $(0.000321) per kWh. On August 19, 2017, the PSA rate was revised to $0.000555 per kWh as part of the 2017 Rate Case Decision. This new rate was comprised of a forward component of $0.000876 per kWh and a historical component of $(0.000321) per kWh.

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 until the following year and were reflected in the 2019 reset of the PSA.

On November 30, 2018, APS filed its PSA rate for the PSA year beginning February 1, 2019. That rate was $0.001658 per kWh and consisted of a forward component of $0.000536 per kWh and a historical component of $0.001122 per kWh. The 2019 PSA rate is a $0.002897 per kWh decrease compared to 2018. These rates went into effect as filed on February 1, 2019.

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

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

Effective June 1, 2017, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $35.1 million for the twelve-month period beginning June 1, 2017 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, 2017. 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.

On January 31, 2017, APS made a filing with FERC to reduce the Post-Employment Benefits Other than Pension expense reflected in its FERC transmission formula rate calculation to recognize certain savings resulting from plan design changes to the other postretirement benefit plans. A transmission customer intervened and protested certain aspects of APS’s filing. FERC initiated a proceeding under Section 206 of the Federal Power Act to evaluate the justness and reasonableness of the revised formula rate filing APS proposed. APS entered into a settlement agreement with the intervening transmission customer, which was filed with FERC for approval on September 26, 2017. FERC approved the settlement agreement without modification or condition on December 21, 2017.

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

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

APS filed its 2016 annual LFCR adjustment on January 15, 2016, requesting an LFCR adjustment of $46.4 million (a $7.9 million annual increase). The ACC approved the 2016 annual LFCR effective beginning in May 2016. APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of

$63.7 million (a $17.3 million per year increase over 2016 levels). On April 5, 2017, the ACC approved the 2017 annual LFCR adjustment as filed, effective with the first billing cycle of April 2017. 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 (a $3 million per year decrease from 2017 levels). 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). 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 and FERC Tax Filing. 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. 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 requesting that the TEAM be implemented in two steps. The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit. APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million for the remainder of 2018 through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction was effective for the first billing cycle in March 2018.

The impact of the TEAM, 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 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 revenues from the prior year due to lower customer rates through the TEAM 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 to return an additional $86.5 million in tax savings to customers. This second request addresses amortization of non-depreciation related excess deferred taxes previously collected from customers. The ACC has not yet approved this request.

Additionally, as part of this second request, APS informed the ACC of its intent to file a third future request to address the amortization of depreciation related excess deferred taxes, as the Company is currently in the process of seeking IRS guidance regarding the amortization method and period applicable to these depreciation related excess deferred taxes.

The TEAM expressly applies to APS's retail rates with the exception of a small subset of customers taking service under specially-approved tariffs noted above. As discussed under "Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters" above, FERC issued an order on May 22, 2018 authorizing APS to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates.

Net Metering

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

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

In addition, the ACC made the following determinations:


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


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


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

This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is 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 reflects the 10% annual reduction discussed above. The new tariff became effective on October 1, 2018.

On January 23, 2017, TASC sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Arizona Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the

2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

Subpoena from Arizona Corporation Commissioner Robert Burns

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

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

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

On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ amended complaint. On March 6, 2018, Commissioner Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted Commissioner Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. Commissioner Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed. Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019. On February 13, 2019, Commissioner Burns filed a notice of appeal. APS and Pinnacle West cannot predict the outcome of this matter.

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, ACC Commissioner Tobin proposed the Energy Modernization Plan, which consists 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 IRP process. The Energy Modernization Plan includes replacing the current RES standard with a new standard called the CREST, which incorporates the proposals in the Energy Modernization Plan. On February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. As a part of this proposal, the ACC voted in March 2018 to direct utilities to develop a comprehensive biomass generation plan to be included in each utility’s RES Implementation Plan. On July 5, 2018, Commissioner Tobin’s office issued a set of draft CREST rules for the ACC’s consideration.

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 Renewable Energy Standard, 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. Workshops on these energy issues are scheduled to be held throughout 2019. APS cannot predict the outcome of this matter.

Integrated Resource Planning

ACC rules require utilities to develop fifteen-year IRPs which describe how the utility plans to serve customer load in the plan timeframe. The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged. In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans. APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows. Based on an ACC decision, APS is required to file a Preliminary Resource Plan by April 1, 2019 and its final IRP by April 1, 2020.

Four Corners

SCE-Related Matters. On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners. The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general retail rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners. APS made its filing under this provision on December 30, 2013. On December 23, 2014, the ACC approved rate adjustments resulting in a revenue increase of $57.1 million on an annual basis. This included the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings

resulting from the closure of Units 1-3 from the date of closing of the purchase through its inclusion in rates. The 2012 Settlement Agreement also provided for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3. The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $48 million as of December 31, 2018 and is being amortized in rates over a total of 10 years. The ACC's rate adjustment decision was appealed and on September 26, 2017, the Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.

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 provides 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 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 cannot predict whether or if the enforcement division will take any action. 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. That proceeding is pending, and APS cannot predict the outcome of the proceeding.

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

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 approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect on April 26, 2017.

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 decommissioning and other retirement-related costs ($89 million as of December 31, 2018), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2026.

Navajo Plant

The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and the U.S. Department of the Interior have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the current owners of the Navajo Plant will cease operations in December 2019.

On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.

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 ($88 million as of December 31, 2018) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.

Regulatory Assets and Liabilities

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



S		December 31, 2018				December 31, 2017
	Amortization Through	Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	733,351	$	—	$	576,188
Retired power plant costs	2033	28,182		167,164		27,402		188,843
Income taxes - AFUDC equity	2048	6,457		151,467		3,828		142,852
Deferred fuel and purchased power — mark-to-market (Note 16)	2023	31,728		23,768		52,100		34,845
Deferred fuel and purchased power (b) (c)	2019	37,164		—		75,637		—
Four Corners cost deferral	2024	8,077		40,228		8,077		48,305
Income taxes — investment tax credit basis adjustment	2047	1,079		25,522		1,066		26,218
Lost fixed cost recovery (b)	2019	32,435		—		59,844		—
Palo Verde VIEs (Note 18)	2046	—		20,015		—		19,395
Deferred compensation	2036	—		36,523		—		36,413
Deferred property taxes	2027	8,569		66,356		8,569		74,926
Loss on reacquired debt	2038	1,637		13,668		1,637		15,305
Tax expense of Medicare subsidy	2024	1,235		6,176		1,236		7,415
TCA balancing account (b)	2020	3,860		772		1,220		—
AG-1 deferral	2022	2,654		5,819		2,654		8,472
Mead-Phoenix transmission line CIAC	2050	332		10,044		332		10,376
Coal reclamation	2026	1,546		15,607		1,068		12,396
SCR deferral	N/A	—		23,276		—		353
Other	Various	1,947		3,185		3,418		—
Total regulatory assets (d)		$	166,902	$	1,342,941	$	248,088	$	1,202,302


(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 7 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.”

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



		December 31, 2018				December 31, 2017
	Amortization Through	Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act	(a)	$	—	$	1,272,709	$	—	$	1,266,104
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act	2058	6,302		243,691		—		254,170
Asset retirement obligations	2057	—		278,585		—		332,171
Removal costs	(b)	39,866		177,533		18,238		209,191
Other post retirement benefits	(c)	37,864		125,903		37,642		151,985
Income taxes - deferred investment tax credit	2047	2,164		51,120		2,164		52,497
Income taxes - change in rates	2048	2,769		70,069		2,573		70,537
Spent nuclear fuel	2027	6,503		57,002		6,924		62,132
Renewable energy standard (d)	2020	44,966		20		23,155		—
Demand side management (d)	2020	14,604		4,123		3,066		4,921
Sundance maintenance	2030	1,278		17,228		—		16,897
Deferred gains on utility property	2022	4,423		6,581		4,423		10,988
Four Corners coal reclamation	2038	1,858		17,871		1,858		18,921
Tax expense adjustor mechanism (d)	2019	3,237		—		—		—
Other	Various	42		3,541		43		2,022
Total regulatory liabilities		$	165,876	$	2,325,976	$	100,086	$	2,452,536

(a)

While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months. See Note 4.


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


(c)	See Note 7.

(d)

See “Cost Recovery Mechanisms” discussion above.

Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

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 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.

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 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 is substantially offset by a net regulatory liability. As of December 31, 2017, to reflect the $1.14 billion reduction in its net deferred income tax liabilities caused by the rate reduction, APS has recorded a net regulatory liability of $1.52 billion and a new $377 million net deferred tax asset. The Company will amortize the net regulatory liability in accordance with applicable federal income tax laws, which 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, the Company has recorded amortization of FERC jurisdictional net excess deferred tax liabilities, retroactive to January 1, 2018. The Company continues to work with the ACC on a plan to amortize the remaining net excess deferred tax liabilities subject to its jurisdiction. See Note 3 for more details.

In August 2018, Treasury proposed regulations that clarify 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. During the third quarter the Company recorded deferred tax liabilities of approximately $11 million and an increase in its net regulatory liability for excess deferred taxes of approximately $9 million, primarily related to bonus depreciation benefits claimed on the Company’s 2017 tax return as a result of this clarifying guidance. However, the proposed regulations are ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. On December 20, 2018, the Joint Committee on Taxation (“JCT”) released the general explanation of the Tax Act. The document - commonly referred to as the "Blue Book" - provides a comprehensive technical description of the Tax Act and includes the legislative intent of Congress with respect to the changes made by provisions of the Tax Act. The “Blue Book” provides clarification that the intent of the Tax Act was to exclude from the definition of bonus depreciation qualified property any property placed in service by a regulated public utility after December 31, 2017. In a footnote, the JCT indicated that a technical correction bill may be necessary to reflect this intent.

Management recognizes tax positions which it believes are "more likely than not" to be sustained upon examination. In applying this "more likely than not" assessment, the Company is required to consider the technical merits of a position, including legislative intent. As a result, while no legislation has been passed which clarifies the ambiguities related to bonus depreciation for property placed in service on or after January 1, 2018, the Company currently believes the continued availability of bonus depreciation is not "more likely than not" to be sustained upon examination. As a result, the Company has not recognized any current or deferred tax benefits related to bonus depreciation for property placed in service on or after January 1, 2018.

For the quarter ending March 31, 2018, the Company early adopted ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income and elected to reclassify the income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings. See Note 2 for additional information.

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

Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax (see Note 18). As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income.

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
	2018			2017			2016			2018			2017			2016
Total unrecognized tax benefits, January 1	$	41,966		$	36,075		$	34,447		$	41,966		$	36,075		$	34,447
Additions for tax positions of the current year	3,436			2,937			2,695			3,436			2,937			2,695
Additions for tax positions of prior years	2,696			4,783			886			2,696			4,783			886
Reductions for tax positions of prior years for:
Changes in judgment	(1,764		)	(1,829		)	(1,953		)	(1,764		)	(1,829		)	(1,953		)
Settlements with taxing authorities	—			—			—			—			—			—
Lapses of applicable statute of limitations	(5,603		)	—			—			(5,603		)	—			—
Total unrecognized tax benefits, December 31	$	40,731		$	41,966		$	36,075		$	40,731		$	41,966		$	36,075

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
	2018		2017		2016		2018		2017		2016
Tax positions, that if recognized, would decrease our effective tax rate	$	19,504	$	16,373	$	11,313	$	19,504	$	16,373	$	11,313

As of the balance sheet date, the tax year ended December 31, 2015 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 2014.

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
	2018			2017		2016		2018			2017		2016
Unrecognized tax benefit interest expense/(benefit) recognized	$	(780	)	$	577	$	529	$	(780	)	$	577	$	529

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
	2018		2017		2016		2018		2017		2016
Unrecognized tax benefit interest accrued	$	1,130	$	1,910	$	1,333	$	1,130	$	1,910	$	1,333

Additionally, as of December 31, 2018, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

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



	Pinnacle West Consolidated						APS Consolidated
	Year Ended December 31,						Year Ended December 31,
	2018		2017		2016		2018		2017		2016
Current:
Federal	$	18,375	$	11,624	$	8,630	$	88,180	$	21,512	$	711
State	3,342		3,052		1,259		1,877		2,778		4,276
Total current	21,717		14,676		9,889		90,057		24,290		4,987
Deferred:
Federal	94,721		223,729		201,743		32,436		221,078		215,178
State	17,464		19,867		24,779		22,321		23,800		25,677
Total deferred	112,185		243,596		226,522		54,757		244,878		240,855
Income tax expense	$	133,902	$	258,272	$	236,411	$	144,814	$	269,168	$	245,842

The following chart compares pretax income at the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 to income tax expense (dollars in thousands):



	Pinnacle West Consolidated									APS Consolidated
	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2018			2017			2016
Federal income tax expense at statutory rate	$	139,533		$	268,177		$	244,278		$	154,260		$	277,540		$	254,617
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	16,411			14,897			16,311			19,091			17,276			18,750
Nondeductible expenditures associated with ballot initiative	7,879			—			—			—			—			—
Stock compensation	(1,804		)	(6,659		)	(2,951		)	(780		)	(3,489		)	(1,937		)
Excess deferred income taxes - Tax Cuts and Jobs Act	(6,725		)	9,348			—			(4,715		)	9,431			—
Allowance for equity funds used during construction (see Note 1)	(7,231		)	(12,937		)	(11,724		)	(7,231		)	(12,937		)	(11,724		)
Palo Verde VIE noncontrolling interest (see Note 18)	(4,094		)	(6,823		)	(6,823		)	(4,094		)	(6,823		)	(6,823		)
Investment tax credit amortization	(6,742		)	(6,715		)	(5,887		)	(6,742		)	(6,715		)	(5,887		)
Other	(3,325		)	(1,016		)	3,207			(4,975		)	(5,115		)	(1,154		)
Income tax expense	$	133,902		$	258,272		$	236,411		$	144,814		$	269,168		$	245,842

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



	Pinnacle West Consolidated						APS Consolidated
	December 31,						December 31,
	2018			2017			2018			2017
DEFERRED TAX ASSETS
Risk management activities	$	15,785		$	25,103		$	15,785		$	25,103
Regulatory liabilities:
Excess deferred income taxes - Tax Cuts and Jobs Act	376,869			376,906			376,869			376,906
Asset retirement obligation and removal costs	117,201			135,847			117,201			135,847
Unamortized investment tax credits	53,284			54,661			53,284			54,661
Other postretirement benefits	40,532			47,021			40,532			47,021
Other	40,380			37,489			40,380			37,489
Pension liabilities	112,019			83,126			107,009			77,280
Coal reclamation liabilities	47,508			45,802			47,508			45,802
Renewable energy incentives	30,779			33,546			30,779			33,546
Credit and loss carryforwards	1,755			53,946			—			1,920
Other	58,820			56,630			59,919			62,421
Total deferred tax assets	894,932			950,077			889,266			897,996
DEFERRED TAX LIABILITIES
Plant-related	(2,277,724		)	(2,220,886		)	(2,277,724		)	(2,220,886		)
Risk management activities	(237		)	(491		)	(237		)	(491		)
Other postretirement assets and other special use funds	(57,697		)	(66,134		)	(57,274		)	(65,733		)
Regulatory assets:
Allowance for equity funds used during construction	(39,086		)	(36,365		)	(39,086		)	(36,365		)
Deferred fuel and purchased power	(23,086		)	(40,778		)	(23,086		)	(40,778		)
Pension benefits	(181,504		)	(142,848		)	(181,504		)	(142,848		)
Retired power plant costs (see Note 3)	(48,348		)	(53,611		)	(48,348		)	(53,611		)
Other	(72,096		)	(74,423		)	(72,096		)	(74,423		)
Other	(2,575		)	(5,346		)	(2,575		)	(5,346		)
Total deferred tax liabilities	(2,702,353		)	(2,640,882		)	(2,701,930		)	(2,640,481		)
Deferred income taxes — net	$	(1,807,421	)	$	(1,690,805	)	$	(1,812,664	)	$	(1,742,485	)

As of December 31, 2018, the deferred tax assets for credit and loss carryforwards relate primarily to federal general business credits of approximately $14 million, which first begin to expire in 2036, and state credit carryforwards net of federal benefit of $7 million, which first begin to expire in 2023. The credit and loss carryforwards amount above has been reduced by $19 million of unrecognized tax benefits.

Lines of Credit and Short-Term Borrowings

12 Months Ended

Dec. 31, 2018

Lines of Credit and Short-Term Borrowings

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.

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2018 and 2017 (dollars in thousands):



	December 31, 2018								December 31, 2017
	Pinnacle West			APS		Total			Pinnacle West			APS		Total
Commitments under Credit Facilities	$	350,000		$	1,000,000	$	1,350,000		$	325,000		$	1,000,000	$	1,325,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(76,400		)	—		(76,400		)	(95,400		)	—		(95,400		)
Amount of Credit Facilities Available	$	273,600		$	1,000,000	$	1,273,600		$	229,600		$	1,000,000	$	1,229,600

Weighted-Average Commitment Fees	0.125%			0.100%					0.125%			0.100%

Pinnacle West

On June 28, 2018, Pinnacle West refinanced its 364-day $125 million unsecured revolving credit facility that would have matured on July 30, 2018 with a new 364-day $150 million credit facility that matures June 27, 2019. Borrowings under the facility bear interest at LIBOR plus 0.70% per annum. At December 31, 2018, Pinnacle West had $54 million outstanding under the facility.

On July 12, 2018, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2021, with a new $200 million facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2018, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $22 million of commercial paper borrowings.

APS

On July 12, 2018, APS replaced its $500 million revolving credit facility that would have matured in May 2021, with a new $500 million facility that matures in July 2023.

At December 31, 2018, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and the above-mentioned $500 million facility. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2018, APS had no commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 10 for a discussion of APS's other outstanding letters of credit.

Debt Provisions

On November 27, 2018, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power). See Note 6 for additional long-term debt provisions.

Long-Term Debt and Liquidity Matters

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

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, 2018 and 2017 (dollars in thousands):



	Maturity	Interest	December 31,
	Dates (a)	Rates	2018			2017
APS
Pollution control bonds:
Variable	2029	(b)	$	35,975		$	35,975
Fixed	2024	4.70%	115,150			147,150
Total pollution control bonds			151,125			183,125
Senior unsecured notes	2019-2048	2.20%-8.75%	4,575,000			4,275,000
Term loans		(c)	—			150,000
Unamortized discount			(12,638		)	(11,288		)
Unamortized premium			7,736			8,049
Unamortized debt issuance cost			(31,787		)	(31,594		)
Total APS long-term debt			4,689,436			4,573,292
Less current maturities			500,000			82,000
Total APS long-term debt less current maturities			4,189,436			4,491,292
Pinnacle West
Senior unsecured notes	2020	2.25%	300,000			300,000
Term loan	2020	(d)	150,000			—
Unamortized discount			(121		)	(184		)
Unamortized debt issuance cost			(1,083		)	(1,395		)
Total Pinnacle West long-term debt			448,796			298,421
Less current maturities			—			—
Total Pinnacle West long-term debt less current maturities			448,796			298,421
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	4,638,232		$	4,789,713


(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 1.76% at December 31, 2018 and 1.77% at December 31, 2017.


(c)	The weighted-average interest rate was 2.24% at December 31, 2017.


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

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
2019	$	500,000	$	500,000
2020	700,000		250,000
2021	—		—
2022	—		—
2023	—		—
Thereafter	3,976,125		3,976,125
Total	$	5,176,125	$	4,726,125

Debt Fair Value

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



	As of December 31, 2018				As of December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	448,796	$	443,955	$	298,421	$	298,608
APS	4,689,436		4,789,608		4,573,292		5,006,348
Total	$	5,138,232	$	5,233,563	$	4,871,713	$	5,304,956

Credit Facilities and Debt Issuances

Pinnacle West

On December 21, 2018, Pinnacle West entered into a $150 million term loan facility that matures December 2020. The proceeds were used for general corporate purposes.

APS

On May 30, 2018, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2017.

On June 26, 2018, APS repaid at maturity APS's $50 million term loan facility.

On August 9, 2018, APS issued $300 million of 4.20% unsecured senior notes that mature on August 15, 2048. The net proceeds from the sale of the notes were used to repay commercial paper borrowings.

On November 30, 2018, APS repaid its $100 million term loan facility that would have matured April 22, 2019.

On December 21, 2018, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.

See “Lines of Credit and Short-Term Borrowings” in Note 5 and “Financial Assurances” in Note 10 for discussion of APS’s separate outstanding letters of credit.

Debt Provisions

Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2018, the ratio was approximately 50% for Pinnacle West and 46% for APS. Failure to comply with such covenant levels would result in an event of default, which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

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

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

Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On November 27, 2018, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved an increase in APS’s long-term debt authorization from $5.1 billion to $5.9 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. See Note 5 for additional short-term debt provisions.

Retirement Plans and Other Benefits

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Retirement Plans and Other Benefits

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.

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

Because of plan changes in 2014, the Company sought IRS approval to move approximately $186 million of other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. On January 2, 2018, these funds were moved to the new trust account, which is included in the other special use funds on the Consolidated Balance Sheets. The Company and the IRS executed a final Closing Agreement on March 2, 2018. The Company made an informational filing with FERC during February 2018. It is the Company’s understanding that completion of these regulatory requirements permits access to approximately $186 million for the sole purpose of paying active union employee medical 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 13 for further discussion of how fair values are determined. Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.

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

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



	Pension									Other Benefits
	2018			2017			2016			2018			2017			2016
Service cost-benefits earned during the period	$	56,669		$	54,858		$	53,792		$	21,100		$	17,119		$	14,993
Interest cost on benefit obligation	124,689			129,756			131,647			28,147			29,959			29,721
Expected return on plan assets	(182,853		)	(174,271		)	(173,906		)	(42,082		)	(53,401		)	(36,495		)
Amortization of:
Prior service cost (credit)	—			81			527			(37,842		)	(37,842		)	(37,883		)
Net actuarial loss	32,082			47,900			40,717			—			5,118			4,589
Net periodic benefit cost (benefit)	$	30,587		$	58,324		$	52,777		$	(30,677	)	$	(39,047	)	$	(25,075	)
Portion of cost charged to expense	$	10,120		$	27,295		$	26,172		$	(21,426	)	$	(18,274	)	$	(12,435	)

On January 1, 2018, we adopted new accounting standard ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This new standard changed our income statement presentation of net periodic benefit cost/(credits) and allows only the service cost component of net periodic benefit cost to be eligible for capitalization. See Note 2 for additional information.

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2018 and 2017 (dollars in thousands):



	Pension						Other Benefits
	2018			2017			2018			2017
Change in Benefit Obligation
Benefit obligation at January 1	$	3,394,186		$	3,204,462		$	753,393		$	716,445
Service cost	56,669			54,858			21,100			17,119
Interest cost	124,689			129,756			28,147			29,959
Benefit payments	(184,161		)	(166,342		)	(31,540		)	(30,144		)
Actuarial (gain) loss	(200,757		)	171,452			(94,329		)	20,014
Benefit obligation at December 31	3,190,626			3,394,186			676,771			753,393
Change in Plan Assets
Fair value of plan assets at January 1	3,057,027			2,675,357			1,022,371			882,651
Actual return on plan assets	(201,078		)	428,374			(40,354		)	139,367
Employer contributions	50,000			100,000			—			353
Benefit payments	(172,473		)	(146,704		)	(72,453		)	—
Transfer to active union medical account	—			—			(185,887		)	—
Fair value of plan assets at December 31	2,733,476			3,057,027			723,677			1,022,371
Funded Status at December 31	$	(457,150	)	$	(337,159	)	$	46,906		$	268,978

The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2018 and 2017 (dollars in thousands):



	2018		2017
Projected benefit obligation	$	3,190,626	$	3,394,186
Accumulated benefit obligation	3,038,774		3,227,233
Fair value of plan assets	2,733,476		3,057,027

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2018 and 2017 (dollars in thousands):



	Pension						Other Benefits
	2018			2017			2018		2017
Noncurrent asset	$	—		$	—		$	46,906	$	268,978
Current liability	(13,980		)	(9,859		)	—		—
Noncurrent liability	(443,170		)	(327,300		)	—		—
Net amount recognized	$	(457,150	)	$	(337,159	)	$	46,906	$	268,978

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2018 and 2017 (dollars in thousands):



	Pension						Other Benefits
	2018			2017			2018			2017
Net actuarial loss	$	794,292		$	643,199		$	63,544		$	75,439
Prior service credit	—			—			(227,733		)	(265,575		)
APS’s portion recorded as a regulatory (asset) liability	(733,351		)	(576,188		)	163,767			189,627
Income tax expense (benefit)	(15,083		)	(24,915		)	561			853
Accumulated other comprehensive loss	$	45,858		$	42,096		$	139		$	344

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 2019 (dollars in thousands):



	Pension		Other Benefits
Net actuarial loss	$	43,248	$	—
Prior service credit	—		(37,821		)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2019	$	43,248	$	(37,821	)

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,
	2018		2017		2018		2017		2016
Discount rate – pension	4.34	%	3.65	%	3.65	%	4.08	%	4.37	%
Discount rate – other benefits	4.39	%	3.71	%	3.71	%	4.17	%	4.52	%
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		6.05	%	6.55	%	6.90	%
Expected long-term return on plan assets - other benefits	N/A		N/A		5.40	%	6.05	%	4.45	%
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	%	5.00	%	5.00	%
Ultimate healthcare cost trend rate	4.75	%	4.75	%	4.75	%	5.00	%	5.00	%
Number of years to ultimate trend rate (pre-65 participants)	7		8		8		4		4

In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. For 2019, we are assuming a 6.25% long-term rate of return for pension assets and 5.55% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

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, 2018 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	$	10,235	$	(4,322	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	11,223		(8,479		)
Effect on the accumulated other postretirement benefit obligation	101,224		(81,144		)

Plan Assets

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

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

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

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

Based on the IPS, and given the pension plan's funded status at year-end 2018, the target and actual allocation for the pension plan at December 31, 2018 are as follows:



	Pension
	Target Allocation		Actual Allocation
Long-term fixed income assets	62	%	64	%
Return-generating assets	38	%	36	%
Total	100	%	100	%

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

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



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

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

As of December 31, 2018, 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, 2018:



	Other Benefits
	Actual Allocation
Long-term fixed income assets	69	%
Return-generating assets	31	%
Total	100	%

See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income, U.S. Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. U.S. Treasury Futures Contracts are valued using the quoted active market prices from the exchange on which they trade, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality. These instruments are classified as Level 2.

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

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

NAV for trusts investing in real estate is derived from the appraised values of the trust's underlying real estate assets. As of December 31, 2018, the plans were able to transact in the common and collective trusts at NAV.

Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships' underlying assets. The plan's partnerships holdings relate to investments in high-yield fixed income instruments and assets of privately held portfolio companies. Certain partnerships also include funding commitments that may require the plan to contribute up to $75 million to these partnerships; as of December 31, 2018, approximately $62 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.

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



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2018
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 net asset value 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.

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2017, by asset category, are as follows (dollars in thousands):



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2017
Pension Plan:
Cash and cash equivalents	$	3,830	$	—	$	—	$	3,830
Fixed income securities:
Corporate	—		1,365,194		—		1,365,194
U.S. Treasury	221,291		—		—		221,291
Other (b)	—		100,599		—		100,599
Common stock equities (c)	228,088		—		—		228,088
Mutual funds (d)	233,732		—		—		233,732
Common and collective trusts:
Equities	—		—		408,763		408,763
Real estate	—		—		171,569		171,569
Fixed Income	—		—		90,869		90,869
Partnerships	—		—		133,379		133,379
Short-term investments and other (e)	—		1,208		98,505		99,713
Total	$	686,941	$	1,467,001	$	903,085	$	3,057,027
Other Benefits:
Cash and cash equivalents	$	143	$	—	$	—	$	143
Fixed income securities:
Corporate	—		306,008		—		306,008
U.S. Treasury	336,963		—		—		336,963
Other (b)	—		32,508		—		32,508
Common stock equities (c)	196,153		—		—		196,153
Mutual funds (d)	39,269		—		—		39,269
Common and collective trusts:
Equities	—		—		75,310		75,310
Real estate	—		—		15,422		15,422
Short-term investments and other (e)	11,268		149		9,178		20,595
Total	$	583,796	$	338,665	$	99,910	$	1,022,371


(a)	These investments primarily represent assets valued using net asset value 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 $50 million in 2018, $100 million in 2017, and $100 million in 2016. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $350 million during the 2019-2021 period.

With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2018. We made a contribution of approximately $1 million in each of 2017 and 2016. We do not expect to make any contributions over the next three years to our other postretirement benefit plans. In 2018, the Company was reimbursed $72 million for prior years retiree medical claims from the other postretirement benefit plan trust assets.

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
2019	$	188,492	$	32,622
2020	193,087		34,199
2021	198,471		35,551
2022	204,399		36,673
2023	211,346		37,405
Years 2024-2028	1,093,319		187,023

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 2018, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $11 million for 2018, $10 million for 2017, and $10 million for 2016.

Leases

12 Months Ended

Dec. 31, 2018

Leases [Abstract]

Leases

We lease certain vehicles, land, buildings, equipment and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.

Lease expense recognized in the Consolidated Statements of Income was $18 million in 2018, $18 million in 2017, and $16 million in 2016. APS’s lease expense was $17 million in 2018, $17 million in 2017, and $15 million in 2016. These amounts do not include purchased power lease contracts, discussed below.

Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in thousands):



Year	Pinnacle West Consolidated		APS
2019	$	13,747	$	13,411
2020	12,428		12,143
2021	9,478		9,282
2022	6,513		6,321
2023	5,359		5,171
Thereafter	42,236		40,656
Total future lease commitments	$	89,761	$	86,984

In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary. As the primary beneficiary, APS consolidated these lessor trust entities. The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation. See Note 18 for a discussion of VIEs.

Purchased Power Lease Contracts

A purchased power contract may contain a lease for accounting purposes. This generally occurs when a purchased power contract designates a specific power plant from which the buyer purchases substantially all of the output and also meets other required lease accounting criteria. APS has certain purchased power contracts that contain lease arrangements. The future minimum lease payments due under these contracts are $54 million, all of which relate to 2019. Due to the inherent uncertainty associated with the reliability of the fuel source, payments under most renewable purchased power lease contracts are considered contingent rents and are excluded from future minimum lease payments. See Note 10 for additional information on our purchased power contract estimated commitments.

Operating lease cost for purchased power lease contracts was $47 million in 2018, $60 million in 2017 and $82 million in 2016. In addition, contingent rents for purchased power lease contracts was $109 million in 2018, $100 million in 2017, and $88 million in 2016. These costs are recorded in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES. See Note 3.

See Note 2 for a discussion of the new lease accounting standard we adopted on January 1, 2019.

Jointly-Owned Facilities

12 Months Ended

Dec. 31, 2018

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

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, 2018 (dollars in thousands):



	Percent Owned			Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%		$	1,887,729	$	1,095,878	$	25,185
Palo Verde Unit 2 (a)	16.8	%		638,419		369,372		20,852
Palo Verde Common	28.0	%	(b)	752,300		277,414		39,995
Palo Verde Sale Leaseback			(a)	351,050		245,275		—
Four Corners Generating Station	63.0	%		1,466,579		544,308		23,430
Cholla common facilities (c)	50.5	%		183,390		82,434		893
Transmission facilities:
ANPP 500kV System	33.5	%	(b)	129,587		49,340		2,705
Navajo Southern System	26.7	%	(b)	82,046		30,464		284
Palo Verde — Yuma 500kV System	19.0	%	(b)	15,304		6,729		530
Four Corners Switchyards	63.1	%	(b)	68,707		15,436		1,334
Phoenix — Mead System	17.1	%	(b)	39,329		18,527		44
Palo Verde — Rudd 500kV System	50.0	%		93,887		25,573		302
Morgan — Pinnacle Peak System	64.6	%	(b)	117,722		16,744		—
Round Valley System	50.0	%		515		153		—
Palo Verde — Morgan System	87.9	%	(b)	219,292		6,660		—
Hassayampa — North Gila System	80.0	%		142,541		9,805		—
Cholla 500kV Switchyard	85.7	%		5,078		1,414		38
Saguaro 500kV Switchyard	60.0	%		20,414		12,790		—
Kyrene — Knox System	50.0	%		578		307		—


(a)	See Note 18.


(b)	Weighted-average of interests.


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

APS also has a 14% ownership in the Navajo Plant. In the second quarter of 2017, APS’s remaining net book value of its interest was reclassified from property, plant and equipment to a regulatory asset. See “Navajo Plant” in Note 3 for more details.

Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

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"). The lawsuit sought to recover damages incurred due to the DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste ("Standard Contract") for failing to accept Palo Verde's spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and the DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by the DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. APS’s share of this amount is $16.7 million. Amounts recovered in the lawsuit and settlement were recorded as adjustments to a regulatory liability and had no impact on the amount of reported net income. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019.

APS has submitted four claims pursuant to the terms of the August 18, 2014 settlement agreement, for four separate time periods during July 1, 2011 through June 30, 2018. The DOE has approved and paid $74.2 million for these claims (APS’s share is $21.6 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 3). APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement was submitted to the DOE on October 31, 2018 in the amount of $10.2 million (APS's share is $3.0 million). This claim is pending DOE review.

Nuclear Insurance

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act ("Price-Anderson Act"), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately $14.1 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers ("ANI"). The remaining balance of approximately $13.6 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million.

The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion. APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited

("NEIL"). APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $24.8 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $71.2 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.

Fuel and Purchased Power Commitments and Purchase Obligations

APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2019 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $622 million in 2019; $555 million in 2020; $558 million in 2021; $563 million in 2022; $560 million in 2023; and $5.9 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, see Note 8.

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,
	2019		2020		2021		2022		2023		Thereafter
Coal take-or-pay commitments (a)	$	179,879	$	181,059	$	184,944	$	186,244	$	187,518	$	1,422,253


(a)	Total take-or-pay commitments are approximately $2.3 billion. The total net present value of these commitments is approximately $1.7 billion.

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



	Year Ended December 31,
	2018		2017		2016
Total purchases	$	206,093	$	165,220	$	160,066

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 $37 million in 2019; $36 million in 2020; $34 million in 2021; $31 million in 2022; $30 million in 2023; and $155 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy.

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 $213 million at December 31, 2018 and $216 million at December 31, 2017. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $32 million in 2019; $21 million in 2020; $21 million in 2021; $22 million in 2022; $24 million in 2023; and $167 million thereafter. Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements.

Superfund-Related Matters

The Comprehensive Environmental Response Compensation and Liability Act ("CERCLA" or "Superfund") establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to, or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible ("PRPs"). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, Operable Unit 3 ("OU3") in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study ("RI/FS"). Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS in the fall or winter of 2019. We estimate that our costs related to this investigation and study will be approximately $2 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.

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

On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID's CERCLA claims concerning both past and future cost recovery. APS's share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. In addition, APS and certain other parties not named in the remaining RID service provider lawsuit may be brought into the litigation via third-party complaints filed by the current direct defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.

Environmental Matters

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

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

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

Navajo Plant. APS estimates that its share of costs for upgrades at the Navajo Plant, based on EPA’s Federal Implementation Plan ("FIP"), could be up to approximately $200 million; however, given the future plans for the Navajo Plant, we do not expect to incur these costs. See "Navajo Plant" in Note 3 for information regarding future plans for the Navajo Plant.

Cholla. APS believed that EPA’s original 2012 final rule establishing controls constituting BART for Cholla, which would require installation of SCR controls, was unsupported and that EPA had no basis for disapproving Arizona’s State Implementation Plan ("SIP") and promulgating a FIP that was inconsistent with the state’s considered BART determinations under the regional haze program. In September 2014, APS met with EPA to propose a compromise BART strategy, whereby APS would permanently close Cholla Unit 2 and cease burning coal at Units 1 and 3 by the mid-2020s. (See Note 3 for 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.

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

On December 16, 2016, President Obama signed the Water Infrastructure Improvements for the Nation ("WIIN") Act into law, which contains a number of provisions requiring EPA to modify the self-implementing provisions of the Agency's current CCR rules under Subtitle D. Such modifications include new EPA authority to directly enforce the CCR rules through the use of administrative orders and providing states, like Arizona, where the Cholla facility is located, the option of developing CCR disposal unit permitting programs, subject to EPA approval. For facilities in states that do not develop state-specific permitting programs, EPA is required to develop a federal permit program, pending the availability of congressional appropriations. By contrast, for facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation, where the Navajo Plant and Four Corners facilities are located, EPA is required to develop a federal permit program regardless of appropriated funds.

ADEQ has initiated a process to evaluate how to develop a state CCR permitting program that would cover electric generating units ("EGUs"), including Cholla. While APS has been working with ADEQ on the development of this program, we are unable to predict when Arizona will be able to finalize and secure EPA approval for a state-specific CCR permitting program. With respect to the Navajo Nation, APS has sought clarification as to when and how EPA would be initiating permit proceedings for facilities on the reservation, including Four Corners. We are unable to predict at this time when EPA will be issuing CCR management permits for the facilities on the Navajo Nation. At this time, it remains unclear how the CCR provisions of the WIIN Act will affect APS and its management of CCR.

Based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCR, which were premised in part on the CCR provisions of the 2016 WIIN Act, on September 13, 2017 EPA agreed to evaluate whether to revise these federal CCR regulations. On July 17, 2018, EPA finalized a revision to its RCRA Subtitle D regulations for CCR, the "Phase I, Part I" revision to its CCR regulations, deferring for future action a number of other proposed changes contemplated in a March 1, 2018 proposal. For the final rule issued on July 17, 2018, EPA established nationwide health-based standards for certain constituents of CCR subject to groundwater corrective action and delayed the closure deadlines for certain unlined CCR surface impoundments by 18 months (for example, those disposal units required to undergo forced closure). These changes to the federal regulations governing CCR disposal are unlikely to have a material impact on APS. As for those aspects of the March 2018 rulemaking proposal for which EPA has yet to take final action, it remains unclear which specific provisions of the federal CCR rules will ultimately be modified, how they will be modified, or when such modification will occur.

Pursuant to a June 24, 2016 order by the D.C. Circuit Court of Appeals in the litigation by industry- and environmental-groups challenging EPA’s CCR regulations, EPA is required to complete a rulemaking proceeding in the near future concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCR rules. Simultaneously with the issuance of EPA's proposed modifications to the federal CCR rules in response to industry petitions, on March 1, 2018, EPA issued a proposed rule seeking comment as to whether or not boron should be included on this list. EPA is not required to take final action approving the inclusion of boron. Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase APS's costs of compliance with the CCR rule at our coal-fired generating facilities. At this time APS cannot predict the eventual results of this rulemaking proceeding concerning boron.

On August 21, 2018, the D.C. Circuit Court issued its decision on the merits in this litigation. The Court upheld the legality of EPA’s CCR regulations, though it vacated and remanded back to EPA a number of specific provisions, which are to be corrected in accordance with the Court’s order. Among the issues affecting APS’s management of CCR, the D.C. Circuit’s decision vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, even where those unlined impoundments have not otherwise violated a regulatory location restriction or groundwater protection standard (i.e., otherwise triggering forced closure). At this time, it remains unclear how this D.C. Circuit Court decision will affect APS’s operations or any financial impacts, as EPA has yet to take regulatory action on remand to revise its 2015 CCR regulations consistent with the Court’s order.

Based on this decision, on December 17, 2018, certain environmental groups filed an emergency motion with the D.C. Circuit to either stay or summarily vacate EPA's July 17, 2018 final rule extending the closure-initiation deadline for certain unlined CCR surface impoundments until October 2020. In response, EPA filed a motion to remand but not vacate that deadline extension regulation. We cannot predict the outcome of the D.C. Circuit's consideration of these dueling motions, and whether or how such a ruling would affect APS's operations.

APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $22 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $20 million. The Navajo Plant currently disposes of CCR in a dry landfill storage area. APS estimates that its share of incremental costs to comply with the CCR rule for the Navajo Plant is approximately $1 million. Additionally, the CCR rule requires ongoing, phased groundwater monitoring. By October 17, 2017, electric utility companies that own or operate CCR disposal units, such as APS, must have collected sufficient groundwater sampling data to initiate a detection monitoring program. To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule required the initiation of an assessment monitoring program by April 15, 2018.

APS recently completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, all such units must cease operating and initiate closure by October of 2020. APS currently estimates that the additional incremental costs to complete this corrective action and closure work, along with the costs to develop replacement CCR disposal capacity, could be approximately $5 million for both Cholla and Four Corners. APS initiated an assessment of corrective measures on January 14, 2019, and anticipates completing this assessment during the summer of 2019. During this assessment, APS will gather additional groundwater data, solicit input from the public, host public hearings, and select remedies. As such, this $5 million cost estimate may change based upon APS’s performance of the CCR rule’s corrective action assessment process. 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 any potential change to the cost estimate would have a material impact on our financial position, results of operations or cash flows.

Clean Power Plan. On June 2, 2014, EPA issued two proposed rules to regulate greenhouse gas ("GHG") emissions from modified and reconstructed EGUs pursuant to Section 111(b) of the Clean Air Act and existing fossil fuel-fired power plants pursuant to Clean Air Act Section 111(d). On August 3, 2015, EPA finalized carbon pollution standards for EGUs, the "Clean Power Plan". On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan and proposed replacement regulations on August 21, 2018. In addition, judicial challenges to the Clean Power Plan are pending before the D.C. Circuit, though that litigation is currently in abeyance while EPA develops regulatory action to potentially repeal and replace that regulation.

EPA's pending proposal to regulate carbon emissions from EGUs replaces the Clean Power Plan with standards that are based entirely upon measures that can be implemented to improve the heat rate of steam-electric power plants, specifically coal-fired EGUs. In contrast with the Clean Power Plan, EPA's proposed "Affordable Clean Energy Rule" 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. In addition, to address the New Source Review ("NSR") implications of power plant upgrades potentially necessary to achieve compliance with the proposed Affordable Clean Energy Rule standards, EPA also proposed to revise EPA's NSR regulations to more readily authorize the implementation of EGU efficiency upgrades.

We cannot predict the outcome of EPA's regulatory actions related to the August 2015 carbon pollution standards for EGU's, including any actions related to EPA's repeal proposal for the Clean Power Plan or additional rulemaking actions to approve the EPA's recently proposed Affordable Clean Energy Rule. In addition, we cannot predict whether the D.C. Circuit Court will continue to hold the litigation challenging the original Clean Power Plan in abeyance in light of EPA's repeal proposal, which is still pending.

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 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. Oral argument for this appeal has been scheduled for March 2019. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings.

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

On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board ("EAB") concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018. The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis. EPA indicated that it anticipates proposing a replacement NPDES permit by March 2019 and, depending on the extent of public comments concerning that proposal, taking final action on a new NPDES permit by June 2019. At this time, we cannot predict the outcome of EPA's reconsideration of the NPDES permit and whether reconsideration will have a material impact on our financial position, results of operations or cash flows.

Four Corners Coal Supply Agreement

Arbitration

On June 13, 2017, APS received a Demand for Arbitration from NTEC in connection with the Coal Supply Agreement, dated December 30, 2013, under which NTEC supplies coal to APS and the other Four Corners owners (collectively, the “Buyer”) for use at the Four Corners Power Plant (the "2016 Coal Supply Agreement"). NTEC was originally seeking a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement that relates to annual minimum quantities of coal to be purchased by the Buyer. NTEC also alleged a shortfall in the Buyer’s purchases for the initial contract year of approximately $30 million. APS’s share of this amount is approximately $17 million. On September 20, 2017, NTEC amended its Demand for Arbitration, removing its request for a declaratory judgment and at such time was only seeking relief for the alleged shortfall in the Buyer's purchases for the initial contract year.

On June 29, 2018, the parties settled the dispute for $45 million, which includes settlement for the initial contract year and the current contract year. APS’s share of this amount is approximately $34 million. In connection with the settlement, the parties amended the 2016 Coal Supply Agreement, including modifying the provisions that gave rise to this dispute. (See “4CA Matter” below for additional matters agreed to between 4CA and NTEC in the settlement arrangement.) The arbitration was dismissed on July 9, 2018.

Coal Advance Purchase

On March 12, 2018, APS paid to NTEC approximately $24 million as an advance payment for APS’s share of coal under the 2016 Coal Supply Agreement. The coal inventory purchased represents an amount that APS expects to use for its plant operations within the next year.

4CA Matter

On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC had the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. The purchase did not occur during the originally contemplated timeframe. Concurrent with the settlement of the 2016 Coal Supply Agreement matter described above, NTEC and 4CA agreed to allow for the purchase by NTEC of the 7% interest, consistent with the option. On June 29, 2018, 4CA and NTEC entered into an asset purchase agreement providing for the sale to NTEC of 4CA's 7% interest in Four Corners. Completion of the sale was subject to the receipt of approval by FERC, which was received on July 2, 2018, and the sale transaction closed on July 3, 2018. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and will pay 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC's 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West's guarantee is secured by a portion of APS's payments to be owed to NTEC under the 2016 Coal Supply Agreement.

The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest. These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount under this formula due December 31, 2018 for calendar year 2017 is approximately $20 million, which was paid to 4CA on December 14, 2018. The balance of the amount under this formula at December 31, 2018 for calendar year 2018 (up to the date that NTEC purchased the 7% interest) is approximately $10 million, which is due to 4CA at December 31, 2019.

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 certain commodity contract collateral obligations and other transactions. As of December 31, 2018, standby letters of credit totaled $0.2 million and will expire in 2019. As of December 31, 2018, surety bonds expiring through 2019 totaled $17 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.

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

Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2018. Since July 6, 2016, Pinnacle West has issued five parental guarantees for 4CA relating to payment obligations arising from 4CA’s acquisition of El Paso’s 7% interest in Four Corners, and pursuant to the Four Corners participation agreement payment obligations arising from 4CA’s ownership interest in Four Corners, four of which terminated following the sale of 4CA's 7% interest to NTEC. (See "Four Corners Coal Supply Agreement - 4CA Matter" above for information related to this sale.)

In connection with the sale of 4CA's 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. (See "Four Corners Coal Supply Agreement - 4CA Matter" above for information related to this guarantee.) A maximum obligation is not

explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee to be immaterial.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

In 2018, APS recognized an ARO for the removal of hazardous waste containing solar panels at all of our utility scale solar plants, which resulted in an increase to the ARO in the amount of $14 million. In addition, due to the sale of 4CA assets to NTEC in 2018 (see Note 10 for more information on 4CA matters) there was a decrease to the ARO of $9 million. APS recognized an ARO of $7 million for rooftop solar removals in accordance with the obligations included in the customer contracts, which requires APS to remove the panels at the end of the contract life and includes the costs for the disposal of hazardous materials in accordance with environmental regulations. Finally, APS has other ARO adjustments resulting in a net decrease of $1 million.

In 2017, APS received a new decommissioning study for the Navajo Plant. This resulted in an increase to the ARO in the amount of $22 million, an increase in regulatory asset of $2 million and a reduction of the regulatory liability of $20 million.

The following table shows the change in our asset retirement obligations for 2018 and 2017 (dollars in thousands):



	2018			2017
Asset retirement obligations at the beginning of year	$	679,529		$	624,475
Changes attributable to:
Accretion expense	36,876			33,104
Settlements	(9,726		)	—
Estimated cash flow revisions	2,002			21,950
Newly incurred or acquired obligations	17,864			—
Asset retirement obligations at the end of year	$	726,545		$	679,529

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 3.

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2018

Selected Quarterly Financial Information [Line Items]

Selected Quarterly Financial Data (Unaudited)

Consolidated quarterly financial information for 2018 and 2017 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.



	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



	2017 Quarter Ended								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,728	$	944,587	$	1,183,322	$	759,659	$	3,565,296
Operations and maintenance	226,071		220,985		230,839		271,212		949,107
Operating income	67,411		297,257		459,548		85,547		909,763
Income taxes	4,211		88,967		144,319		20,775		258,272
Net income	28,185		172,317		280,945		26,502		507,949
Net income attributable to common shareholders	23,312		167,443		276,072		21,629		488,456

Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.21	$	1.50	$	2.47	$	0.19	$	4.37
Net income attributable to common shareholders — Diluted	0.21		1.49		2.46		0.19		4.35

Selected Quarterly Financial Information [Line Items]

Selected Quarterly Financial Data (Unaudited)

Selected Quarterly Financial Data (Unaudited) - APS

APS's quarterly financial information for 2018 and 2017 is as follows (dollars in thousands):



	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



	2017 Quarter Ended								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,589	$	943,406	$	1,178,846	$	757,811	$	3,557,652
Operations and maintenance	219,008		215,775		222,374		260,826		917,983
Operating income	70,269		296,700		465,658		91,912		924,539
Net income attributable to common shareholder	23,162		169,108		284,256		27,783		504,309

Fair Value Measurements

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

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 — Unadjusted quoted prices in active markets for identical assets or liabilities.

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

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

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, 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 Net Asset Value ("NAV"), as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.

Recurring Fair Value Measurements

We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trust and other special use funds. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans. See Note 7 for fair value discussion of plan assets held in our retirement and other benefit plans.

Cash Equivalents

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

Risk Management Activities — Derivative Instruments

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

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

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

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

Investments Held in Nuclear Decommissioning Trust and Other Special Use Funds

The nuclear decommissioning trust and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union medical trust. See Note 19 for additional discussion about our investment accounts.

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

Fixed Income Securities

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

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

Equity Securities

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

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

Fair Value Tables

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



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Other				Balance at December 31, 2018
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 debt 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.


(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.

The following table presents the fair value at December 31, 2017 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at December 31, 2017
Assets
Cash equivalents	$	10,630	$	—		$	—		$	—			$	10,630
Risk management activities — derivative instruments:
Commodity contracts	—		5,683			1,036			(4,737		)	(b)	1,982
Nuclear decommissioning trust:
Cash and cash equivalents	7,224		—			—			109			(d)	7,333
U.S. commingled equity funds	—		—			—			417,390			(e)	417,390
U.S. Treasury debt	127,662		—			—			—				127,662
Corporate debt	—		114,007			—			—				114,007
Mortgage-backed debt securities	—		111,874			—			—				111,874
Municipal bonds	—		79,049			—			—				79,049
Other fixed income	—		13,685			—			—				13,685
Subtotal nuclear decommissioning trust	134,886		318,615			—			417,499				871,000

Other special use funds (c):	455		31,562			—			525				32,542

Total Assets	$	145,971	$	355,860		$	1,036		$	413,287			$	916,154
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(78,646	)	$	(19,292	)	$	1,516		(b)	$	(96,422	)


(a)	Primarily consists of long-dated electricity contracts.


(b)	Represents counterparty netting, margin, and collateral. See Note 16.


(c)	Primarily consists of fixed income municipal bonds. Presented as coal reclamation escrow in 2017.


(d)	Represents nuclear decommissioning trust net pending securities sales and purchases.


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

Fair Value Measurements Classified as Level 3

The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 3).

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

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, 2018 and December 31, 2017:



	December 31, 2018 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
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.



	December 31, 2017 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Electricity:
Forward Contracts (a)	$	21	$	15,485	Discounted cash flows	Electricity forward price (per MWh)	$18.51 - $38.75	$	27.89
Natural Gas:
Forward Contracts (a)	1,015		3,807		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.33 - $3.11	$	2.71
Total	$	1,036	$	19,292


(a)	Includes swaps and physical and financial contracts.

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, 2018 and 2017 (dollars in thousands):



	Year Ended December 31,
Commodity Contracts	2018			2017
Net derivative balance at beginning of period	$	(18,256	)	$	(47,406	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			—
Included in OCI	—			3
Deferred as a regulatory asset or liability	(1,130		)	(13,643		)
Settlements	(787		)	5,834
Transfers into Level 3 from Level 2	(12,830		)	(10,026		)
Transfers from Level 3 into Level 2	24,789			46,982
Net derivative balance at end of period	$	(8,214	)	$	(18,256	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

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

Financial Instruments Not Carried at Fair Value

The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. See Note 6 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 $61 million as of December 31, 2018, 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 10 for more information on 4CA matters.

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Earnings Per Share

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

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, 2018, 2017 and 2016 (in thousands, except per share amounts):



	2018		2017		2016
Net income attributable to common shareholders	$	511,047	$	488,456	$	442,034
Weighted average common shares outstanding — basic	112,129		111,839		111,409
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	421		528		637
Weighted average common shares outstanding — diluted	112,550		112,367		112,046
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic	$	4.56	$	4.37	$	3.97
Net Income attributable to common shareholders - diluted	$	4.54	$	4.35	$	3.95

Stock-Based Compensation

12 Months Ended

Dec. 31, 2018

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 2012 Long-Term Incentive Plan (“2012 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan authorizes up to 4.6 million common shares to be available for grant. As of December 31, 2018, 1.9 million common shares were available for issuance under the 2012 Plan. During 2018, 2017, and 2016, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan.

Stock-Based Compensation Expense and Activity

Compensation cost included in net income for stock-based compensation plans was $20 million in 2018, $21 million in 2017, and $19 million in 2016. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $7 million in 2018, $15 million in 2017, and $10 million in 2016.

As of December 31, 2018, there were approximately $9 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years.

The total fair value of shares vested was $24 million in 2018, $22 million in 2017 and $22 million in 2016.

The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2018, 2017 and 2016:



	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2018		2017		2016		2018		2017		2016
Units granted	132,997		161,963		141,811		171,708		147,706		166,666
Weighted-average grant date fair value	$	77.51	$	72.60	$	67.34	$	76.56	$	78.99	$	66.60


(a)	Units granted includes awards that will be cash settled of 66,252 in 2018, 67,599 in 2017, and 43,952 in 2016.


(b)	Reflects the target payout level.

The following table is a summary of the status of non-vested awards as of December 31, 2018 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, 2018	291,288			$	69.78	309,502		$	72.46
Granted	132,997			77.51		171,708		76.56
Vested	(147,938	)		67.12		(159,284	)	66.61
Forfeited (c)	(5,356	)		73.42		(9,542	)	73.34
Nonvested at December 31, 2018	270,991		(a)	74.39		312,384		77.67
Vested Awards Outstanding at December 31, 2018	73,144					159,284


(a)	Includes 148,131 of awards that will be cash settled.


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


(c)	We account for forfeitures as they occur.

Share-based liabilities paid relating to restricted stock units were $4 million, $4 million and $3 million in 2018, 2017 and 2016, respectively. This includes cash used to settle restricted stock units of $5 million, $4 million and $3 million in 2018, 2017 and 2016, respectively. Restricted stock units that are cash settled are classified as liability awards. All performance shares are classified as equity awards.

Restricted Stock Units, Stock Grants, and Stock Units

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

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

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

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

Performance Share Awards

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

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.

Derivative Accounting

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.

Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value. See Note 13 for a discussion of fair value measurements. Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.

For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 3). 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, 2018 and 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):



		Quantity
Commodity	Unit of Measure	December 31, 2018	December 31, 2017
Power	GWh	250	583
Gas	Billion cubic feet	218	240

Gains and Losses from Derivative Instruments

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2018, 2017 and 2016 (dollars in thousands):



	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2018			2017			2016
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	—		$	(59	)	$	47
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(2,000		)	(3,519		)	(3,926		)


(a)	During the years ended December 31, 2018, 2017, and 2016, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.


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

During the next twelve months, we estimate that a net loss of $1.5 million before income taxes will be reclassified from accumulated OCI as an offset to the effect of market price changes for the related hedged transactions. In accordance with the PSA, most of these amounts will be recorded as either a regulatory asset or liability and have no immediate effect on earnings.

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2018, 2017 and 2016 (dollars in thousands):



	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2018			2017			2016
Net Gain (Loss) Recognized in Income	Operating revenues	$	(2,557	)	$	(1,192	)	$	771
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	(12,951		)	(87,991		)	25,711
Total		$	(15,508	)	$	(89,183	)	$	26,482


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

Derivative Instruments in the Consolidated Balance Sheets

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

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

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

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

The following tables provide information about the fair value of our risk management activities reported on a gross basis, and the impacts of offsetting as of December 31, 2018 and 2017. 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, 2018: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	3,106		$	(2,149	)	$	957		$	156		$	1,113
Investments and other assets	36			(36		)	—			—			—
Total assets	3,142			(2,185		)	957			156			1,113

Current liabilities	(36,345		)	2,149			(34,196		)	(1,310		)	(35,506		)
Deferred credits and other	(24,567		)	36			(24,531		)	—			(24,531		)
Total liabilities	(60,912		)	2,185			(58,727		)	(1,310		)	(60,037		)
Total	$	(57,770	)	$	—		$	(57,770	)	$	(1,154	)	$	(58,924	)


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


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


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



As of December 31, 2017: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	5,427		$	(3,796	)	$	1,631		$	300		$	1,931
Investments and other assets	1,292			(1,241		)	51			—			51
Total assets	6,719			(5,037		)	1,682			300			1,982

Current liabilities	(59,527		)	3,796			(55,731		)	(3,521		)	(59,252		)
Deferred credits and other	(38,411		)	1,241			(37,170		)	—			(37,170		)
Total liabilities	(97,938		)	5,037			(92,901		)	(3,521		)	(96,422		)
Total	$	(91,219	)	$	—		$	(91,219	)	$	(3,221	)	$	(94,440	)


(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 $3,521 and cash margin provided to counterparties of $300.

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, 2018, Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

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

The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2018 (dollars in thousands):



	December 31, 2018
Aggregate fair value of derivative instruments in a net liability position	$	60,912
Cash collateral posted	—
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	56,876


(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 $94 million if our debt credit ratings were to fall below investment grade.

Other Income and Other Expense

12 Months Ended

Dec. 31, 2018

Component of Other Income and Other Expense Nonoperating [Line Items]

Other Income and Other Expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2018, 2017 and 2016 (dollars in thousands):



	2018			2017			2016
Other income:
Interest income	$	8,647		$	3,497		$	884
Debt return on Four Corners SCR deferral (Note 3)	16,153			354			—
Miscellaneous	96			155			17
Total other income	$	24,896		$	4,006		$	901
Other expense:
Non-operating costs	$	(10,076	)	$	(11,749	)	$	(9,235	)
Investment losses — net	(417		)	(4,113		)	(1,747		)
Miscellaneous	(7,473		)	(5,677		)	(4,355		)
Total other expense	$	(17,966	)	$	(21,539	)	$	(15,337	)

Component of Other Income and Other Expense Nonoperating [Line Items]

Other Income and Other Expense

Other Income and Other Expense - APS

The following table provides detail of APS’s other income and other expense for 2018, 2017 and 2016 (dollars in thousands):



	2018			2017			2016
Other income:
Interest income	$	6,496		$	2,504		$	261
Debt return on Four Corners SCR deferral (Note 3)	16,153			354			—
Miscellaneous	97			155			10
Total other income	$	22,746		$	3,013		$	271
Other expense:
Non-operating costs	$	(9,462	)	$	(10,825	)	$	(8,455	)
Miscellaneous	(5,830		)	(3,088		)	(2,099		)
Total other expense	$	(15,292	)	$	(13,913	)	$	(10,554	)

Palo Verde Sale Leaseback Variable Interest Entities

12 Months Ended

Dec. 31, 2018

Variable Interest Entities [Abstract]

Palo Verde Sale Leaseback Variable Interest Entities

In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2019 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.

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

As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $19 million for 2018, 2017 and 2016. 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, 2018 and December 31, 2017 include the following amounts relating to the VIEs (dollars in thousands):



	December 31, 2018		December 31, 2017
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	105,775	$	109,645
Equity-Noncontrolling interests	125,790		129,040

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.

APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $297 million beginning in 2019, and up to $456 million over the lease extension term.

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

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds

12 Months Ended

Dec. 31, 2018

Investments, Debt and Equity Securities [Abstract]

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, 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 13 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy. The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.

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

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

Active Union Employee Medical Account - APS has investments restricted for paying active union employee medical costs. These investments were transferred from APS other postretirement benefit trust assets into the active union employee medical trust in January 2018 (see Note 7). These investments may be used to pay active union employee medical costs incurred in the current period and in future periods. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including other-than-temporary impairments) in other regulatory assets. Activities relating to active union employee medical account investments are included within the other special use funds in the table below.

APS

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's nuclear decommissioning trust and other special use fund assets at December 31, 2018 and December 31, 2017 (dollars in thousands):



	December 31, 2018
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total			Total Unrealized Gains		Total Unrealized Losses
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.



	December 31, 2017
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total			Total Unrealized Gains		Total Unrealized Losses
Equity Securities	$	424,614	$	430	$	425,044		$	248,623	$	—
Available for Sale-Fixed Income Securities	446,277		29,439		475,716		(a)	11,537		(2,996		)
Other	109		489		598		(b)	—		—
Total	$	871,000	$	30,358	$	901,358		$	260,160	$	(2,996	)


(a)	As of December 31, 2017, the amortized cost basis of these available-for-sale investments is $467 million.


(b)	Represents net pending securities sales and purchases.

The following table sets forth APS's realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the years ended December 31, 2018, 2017 and 2016 (dollars in thousands):



	Year Ended December 31,
	Nuclear Decommissioning Trusts			Other Special Use Funds			Total
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
2016
Realized gains	11,213			—			11,213
Realized losses	(10,106		)	—			(10,106		)
Proceeds from the sale of securities (a)	633,410			—			633,410


(a)	Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds.

Fixed Income Securities Contractual Maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2018 is as follows (dollars in thousands):



	Nuclear Decommissioning		Coal Reclamation Escrow Accounts		Active Union Medical Trust		Total
Less than one year	$	26,819	$	21,237	$	39,966	$	88,022
1 year – 5 years	97,566		15,658		104,128		217,352
5 years – 10 years	128,379		2,511		—		130,890
Greater than 10 years	194,214		6,878		—		201,092
Total	$	446,978	$	46,284	$	144,094	$	637,356

Revenue

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue

On January 1, 2018, we adopted new revenue guidance in ASU 2014-09 and related amendments. The new revenue guidance requires entities to recognize revenue when control of the promised good or service is transferred to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. We applied the new guidance using the modified retrospective method applied to contracts which were not completed as of January 1, 2018. The adoption of the new revenue guidance resulted in expanded disclosures but otherwise did not have a material impact on our financial statements. New revenue disclosures required by the standard are included below, and in Note 1. See Note 2 for additional information regarding the new accounting standard.

Sources of Revenue

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



	Year Ended December 31,
	2018
Retail residential electric service	$	1,867,370
Retail non-residential electric service	1,628,891
Wholesale energy sales	109,198
Transmission services for others	60,261
Other sources	25,527
Total operating revenues	$	3,691,247

We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Our retail electric services and tariff rates are regulated by the ACC. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. Our wholesale activities and tariff rates are regulated by the FERC.

Revenue Activities

Our revenues are primarily derived from activities that are classified as revenues from contracts with customers. This includes sales of electricity to our regulated retail customers and wholesale and transmission activities. Our revenues from contracts with customers for the year ended December 31, 2018 were $3,644 million.

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, 2018, our revenues that do not qualify as revenue from contracts with customers were $47 million. 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 3 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, 2018.

Changes in Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2018

Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:

Changes in Accumulated Other Comprehensive Loss

The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2018 and 2017 (dollars in thousands):



	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2016	$	(39,070	)		$	(4,752	)		$	(43,822	)
OCI (loss) before reclassifications	(6,438		)		(35		)		(6,473		)
Amounts reclassified from accumulated other comprehensive loss	3,068			(a)	2,225			(b)	5,293
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	)


(a)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.

(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.

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT

12 Months Ended

Dec. 31, 2018

Condensed Financial Information Disclosure [Abstract]

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

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,
	2018			2017			2016
Operating revenues	$	—		$	119		$	370
Operating expenses	53,844			24,591			26,573
Operating loss	(53,844		)	(24,472		)	(26,203		)
Other
Equity in earnings of subsidiaries	569,249			507,495			462,027
Other expense	(3,202		)	(2,422		)	(1,622		)
Total	566,047			505,073			460,405
Interest expense	12,074			5,633			3,151
Income before income taxes	500,129			474,968			431,051
Income tax benefit	(10,918		)	(13,488		)	(10,983		)
Net income attributable to common shareholders	511,047			488,456			442,034
Other comprehensive income (loss) — attributable to common shareholders	5,846			(1,180		)	926
Total comprehensive income — attributable to common shareholders	$	516,893		$	487,276		$	442,960

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,
	2018			2017
ASSETS
Current assets
Cash and cash equivalents	$	41		$	41
Accounts receivable	99,989			93,554
Income tax receivable	32,737			19,124
Other current assets	1,502			267
Total current assets	134,269			112,986
Investments and other assets
Investments in subsidiaries	5,859,834			5,465,137
Deferred income taxes	5,243			54,352
Other assets	34,910			44,613
Total investments and other assets	5,899,987			5,564,102
Total Assets	$	6,034,256		$	5,677,088
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	9,565			7,638
Accrued taxes	9,006			8,927
Common dividends payable	82,675			77,667
Short-term borrowings	76,400			95,400
Other current liabilities	19,215			17,417
Total current liabilities	196,861			207,049

Long-term debt less current maturities (Note 6)	448,796			298,421

Pension liabilities	17,766			20,758
Other	22,128			15,130
Total deferred credits and other	39,894			35,888
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
Common stock equity
Common stock	2,629,440			2,609,181
Accumulated other comprehensive loss	(47,708		)	(45,002		)
Retained earnings	2,641,183			2,442,511
Total Pinnacle West Shareholders’ equity	5,222,915			5,006,690
Noncontrolling interests	125,790			129,040
Total Equity	5,348,705			5,135,730
Total Liabilities and Equity	$	6,034,256		$	5,677,088

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,
	2018			2017			2016
Cash flows from operating activities
Net income	$	511,047		$	488,456		$	442,034
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries — net	(569,249		)	(507,495		)	(462,027		)
Depreciation and amortization	76			76			85
Deferred income taxes	49,535			(264		)	(12,402		)
Accounts receivable	(7,881		)	(2,106		)	15,823
Accounts payable	1,967			(11,162		)	10,402
Accrued taxes and income tax receivables — net	(13,535		)	(22,247		)	20,041
Dividends received from subsidiaries	316,000			296,800			239,300
Other	31,807			15,092			5,514
Net cash flow provided by operating activities	319,767			257,150			258,770
Cash flows from investing activities
Construction work in progress	—			—			(18,457		)
Investments in subsidiaries	(142,796		)	(178,027		)	(19,242		)
Repayments of loans from subsidiaries	6,477			2,987			1,026
Advances of loans to subsidiaries	(500		)	(6,388		)	(2,092		)
Net cash flow used for investing activities	(136,819		)	(181,428		)	(38,765		)
Cash flows from financing activities
Issuance of long-term debt	150,000			298,761			—
Short-term debt borrowings under revolving credit facility	20,000			58,000			40,000
Short-term debt repayments under revolving credit facility	(32,000		)	(32,000		)	—
Commercial paper - net	(7,000		)	27,700			1,700
Dividends paid on common stock	(308,892		)	(289,793		)	(274,229		)
Repayment of long-term debt	—			(125,000		)	—
Common stock equity issuance - net of purchases	(5,055		)	(13,390		)	(4,867		)
Other	(1		)	—			—
Net cash flow used for financing activities	(182,948		)	(75,722		)	(237,396		)
Net decrease in cash and cash equivalents	—			—			(17,391		)
Cash and cash equivalents at beginning of year	41			41			17,432
Cash and cash equivalents at end of year	$	41		$	41		$	41

See Combined Notes to Consolidated Financial Statements.

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY

NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY

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

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.

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

12 Months Ended

Dec. 31, 2018

Reserve for uncollectibles

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

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:
2018	$	2,513	$	10,870	$	—	$	9,314	$	4,069
2017	3,037		6,836		—		7,360		2,513
2016	3,125		4,025		—		4,113		3,037

SCHEDULE II - RESERVE FOR UNCOLLECTIBLES

Reserve for uncollectibles

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:
2018	$	2,513	$	10,870	$	—	$	9,314	$	4,069
2017	3,037		6,836		—		7,360		2,513
2016	3,125		4,025		—		4,113		3,037

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Description of Business and Basis of Presentation

Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company's core expertise in the electric energy industry. BCE is currently pursuing transmission opportunities through a joint venture arrangement. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso's 7% interest in Four Corners. See Note 10 for more information on 4CA matters.

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

We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities (see Note 18).

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.

These consolidated financial statements and notes have been prepared consistently, with the exception of the reclassification of certain prior year amounts on our Consolidated Statements of Income and APS's Consolidated Statements of Income. Beginning in the quarter ended March 31, 2018, APS changed the format of presentation of its Consolidated Statements of Income from a utility ratemaking format to a commercial format. Minor changes were made in the description of certain income statement line items and the amounts presented in the comparable prior period also changed by immaterial amounts due to the change from a utility to a non-utility format and also from the adoption of the new accounting guidance for net periodic pension cost and net periodic postretirement benefit cost. In addition, the prior year amounts were reclassified to conform to the current year presentation for the other special use funds in the investment and other assets section on the Consolidated Balance Sheets.

Accounting Records and Use of Estimates

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

Regulatory Accounting

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

Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory environment and recent rate orders applicable to APS or 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.

Electric Revenues

We derive electric revenues primarily from sales of electricity to our regulated Native Load customers. 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 Native Load customers is based on the reading of their meters. We obtain customers' meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed. 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.

On January 1, 2018, we adopted new revenue guidance ASU 2014-09, Revenue from contracts with customers, accordingly our 2018 electric revenues primarily consist of activities that now 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 invoice practical expedient and, as such, we recognize revenue based on the amount to which we have a right to invoice for services performed. See Note 2.

Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase electricity are netted against other contracts to sell electricity. This is called a "book-out" and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which

power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.

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

Allowance for Doubtful Accounts

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

Property, Plant and Equipment

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 11.

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

We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2018 were as follows:

•Fossil plant — 17 years;

•Nuclear plant — 23 years;

•Other generation — 19 years;

•Transmission — 39 years;

•Distribution — 34 years; and

•General plant — 6 years.

Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. 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.

Asset Retirement Obligations

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

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 7.03% for 2018, 6.68% for 2017, and 7.17% for 2016. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

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 6).

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.

Derivative Accounting

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

We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet.

Loss Contingencies and Environmental Liabilities

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

Retirement Plans and Other Postretirement Benefits

Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries. We also sponsor another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. See Note 7 for additional information on pension and other postretirement benefits. On January 1, 2018, we adopted new accounting guidance ASU 2017-07, Compensation-Retirement Benefits: Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost.

Nuclear Fuel

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

APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero. In accordance with a settlement agreement with the DOE in August 2014, we will now accrue a receivable for incurred

claims and an offsetting regulatory liability through the settlement period ending December of 2019.

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. On January 1, 2018, we adopted new guidance ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of certain tax effects from accumulated other comprehensive income. See Note 4 for additional discussion.

Cash and Cash Equivalents

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

Intangible Assets

We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS's software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives.

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

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 trust fund, coal reclamation escrow and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. See Notes 13 and 19 for more information on these investments.

Business Segments

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

New Accounting Standards

Standards Adopted in 2018

ASU 2014-09, Revenue from Contracts with Customers

In May 2014, a new revenue recognition accounting standard was issued. This standard provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. Since the issuance of the new revenue standard, additional guidance was issued to clarify certain aspects of the new revenue standard, including principal versus agent considerations, identifying performance obligations, and other narrow scope improvements. The new revenue standard, and related amendments, became effective for us on January 1, 2018. The standard may be adopted using a full retrospective application or a simplified transition method that allows entities to record a cumulative effect adjustment in retained earnings at the date of initial application.

We adopted this standard and related amendments on January 1, 2018 using the modified retrospective transition approach. The adoption of the new revenue guidance resulted in expanded disclosures, but otherwise did not have a material impact on our financial statements. See Note 20.

ASU 2016-01, Financial Instruments: Recognition and Measurement

In January 2016, a new accounting standard was issued relating to the recognition and measurement of financial instruments. The new guidance requires certain investments in equity securities to be measured at fair value with changes in fair value recognized in net income, and modifies the impairment assessment of certain equity securities. The new standard was effective for us on January 1, 2018. The standard required modified retrospective application, with the exception of certain aspects of the standard that required prospective

application. We adopted this standard on January 1, 2018, using primarily a retrospective approach. Due to regulatory accounting treatment, the adoption of this standard did not have a material impact on our financial statements. See Notes 13 and 19 for disclosures relating to our investments in debt and equity securities.

ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments

In August 2016, a new accounting standard was issued that clarifies how entities should present certain specific cash flow activities on the statement of cash flows. The guidance is intended to eliminate diversity in practice in how entities classify these specific activities between cash flows from operating activities, investing activities and financing activities. The specific activities addressed include debt prepayments and extinguishment costs, proceeds from the settlement of insurance claims, proceeds from corporate-owned life insurance policies, and other activities. The standard also addresses how entities should apply the predominance principle when a transaction includes separately identifiable cash flows. The new standard was effective for us, and was adopted on January 1, 2018, using a retrospective transition method. The adoption of this guidance did not have a significant impact on our financial statements, as either our statement of cash flow presentation is consistent with the new prescribed guidance or we do not have significant activities relating to the specific transactions that are addressed by the new standard.

ASU 2016-18, Statement of Cash Flows: Restricted Cash

In November 2016, a new accounting standard was issued that clarifies how restricted cash and restricted cash equivalents should be presented on the statement of cash flows. The new guidance requires entities to include restricted cash and restricted cash equivalents as a component of the beginning and ending cash and cash equivalent balances on the statement of cash flows. The new standard is effective for us, and was adopted on January 1, 2018, using a retrospective transition method. The adoption of this guidance did not impact our financial statements, as our holdings and activities designated as restricted cash and restricted cash equivalents at transition and in prior periods are insignificant.

ASU 2017-01, Business Combinations: Clarifying the Definition of a Business

In January 2017, a new accounting standard was issued that clarifies the definition of a business. This standard is intended to assist entities with evaluating whether a transaction should be accounted for as an acquisition (or disposal) of assets or a business. The definition of a business affects many areas of accounting, including acquisitions, disposals, goodwill, and consolidation. The new standard was effective for us and was adopted on January 1, 2018 using a prospective transition approach. This standard did not have an impact on our financial statements on the date of adoption.

ASU 2017-05, Other Income: Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets

In February 2017, a new accounting standard was issued that intended to clarify the scope of accounting guidance pertaining to gains and losses from the derecognition of nonfinancial assets, and to add guidance for partial sales of nonfinancial assets. The new standard was effective for us, and was adopted on January 1, 2018, using a modified retrospective transition approach. This standard did not have a significant impact on our financial statements on the date of adoption. On July 3, 2018, 4CA sold its 7% interest in Four Corners. The sale transaction was accounted for in accordance with the guidance in ASU 2017-05, see Note 10.

ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, a new accounting standard was issued that modifies how plan sponsors present net periodic pension cost and net periodic postretirement benefit cost (net benefit costs). The presentation changes require net benefit costs to be disaggregated on the income statement by the various components that comprise these costs. Specifically, only the service cost component is eligible for presentation as an operating income item, and all other cost components are now presented as non-operating items. This presentation change was applied retrospectively. Furthermore, the new standard allows only the service cost component to be eligible for capitalization. The change in capitalization requirements was applied prospectively. The new guidance was effective for us on January 1, 2018.

We adopted this new accounting standard on January 1, 2018. As a result of adopting this standard we have presented the non-service cost components of net benefits costs in other income instead of operating income. Prior year non-service cost components have also been reclassified to conform to this new presentation. We elected to apply the practical expedient guidance. As such, prior period costs have been estimated based on amounts previously disclosed in our pension and other postretirement benefit plan notes. The changes impacting capitalization have been adopted prospectively. As such, upon adoption, we are no longer capitalizing a portion of the non-service cost components of net benefit costs.

In 2018 the non-service credit components are a reduction to total benefit costs. Excluding non-service credits from eligible capitalization costs resulted in the capitalization of an additional $15 million of net benefit costs, with a corresponding increase to pretax income for the year. See Note 7 for additional information related to our pension plans and other postretirement benefits.

ASU 2018-02, Income Statement-Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, new accounting guidance was issued that allows entities an optional election to reclassify the income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings. Amounts eligible for reclassification must relate to the effects from the Tax Act remaining in accumulated other comprehensive income. The new guidance also requires expanded disclosures. This guidance is effective for us on January 1, 2019 with early application permitted. The guidance should be applied either in the period of adoption or retrospectively to each period in which the effect of the Tax Act was recognized.

We early adopted this guidance in the quarter ended March 31, 2018, and we have elected to reclassify the income tax effects of the Tax Act related to other comprehensive income to retained earnings. As of December 31, 2018, on a consolidated basis our accumulated other comprehensive income decreased $9 million, and APS's accumulated other comprehensive income decreased $5 million, as a result of adopting this guidance. Amounts were reclassified from accumulated other comprehensive income to retained earnings, and related to tax rate changes. The adoption of this guidance did not impact our income from continuing operations. See Note 4 for additional discussion of the Tax Act.

Standards Adopted in 2019

ASU 2016-02, Leases

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

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

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

ASU 2017-12, Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities

In August 2017, a new accounting standard was issued that modifies hedge accounting guidance with the intent of simplifying the application of hedge accounting. The new standard became effective for us on January 1, 2019, with early application permitted. At transition, the guidance requires the changes to be applied to hedging relationships existing on the date of adoption, with the effect of adoption reflected as of the beginning of the fiscal year of adoption using a cumulative effect adjustment approach. The presentation and disclosure changes may be applied prospectively. We adopted this standard on January 1, 2019 and because we are not currently applying hedge accounting, the adoption of the standard did not impact our financial statements.

Standards Pending Adoption

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

In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard will require 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. The new standard is effective for us on January 1, 2020 and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

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 is effective for us on January 1, 2020, with early application permitted, and may be applied using either a retrospective or prospective transition approach. We are currently evaluating this new accounting standard and the impacts it may have on our financial statements.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Schedule of property, plant and equipment

Pinnacle West’s property, plant and equipment included in the December 31, 2018 and 2017 Consolidated Balance Sheets is composed of the following (dollars in thousands):



Property, Plant and Equipment:	2018			2017
Generation	$	8,285,514		$	7,963,998
Transmission	3,033,579			2,836,578
Distribution	6,378,345			6,025,856
General plant	1,039,190			971,629
Plant in service and held for future use	18,736,628			17,798,061
Accumulated depreciation and amortization	(6,366,014		)	(6,128,535		)
Net	12,370,614			11,669,526
Construction work in progress	1,170,062			1,291,498
Palo Verde sale leaseback, net of accumulated depreciation	105,775			109,645
Intangible assets, net of accumulated amortization	262,902			257,189
Nuclear fuel, net of accumulated amortization	120,217			117,408
Total property, plant and equipment	$	14,029,570		$	13,445,266

Summary of supplemental cash flow information

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



	Year ended December 31,
	2018		2017		2016
Cash paid during the period for:
Income taxes, net of refunds	$	21,173	$	2,186	$	9,956
Interest, net of amounts capitalized	208,479		189,288		184,462
Significant non-cash investing and financing activities:
Accrued capital expenditures	$	132,620	$	130,404	$	114,855
Dividends declared but not paid	82,675		77,667		72,926
Sale of 4CA 7% interest in Four Corners	68,907		—		—

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Schedule of changes in the deferred fuel and purchased power regulatory asset

The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2018 and 2017 (dollars in thousands):



	Twelve Months Ended December 31,
	2018			2017
Beginning balance	$	75,637		$	12,465
Deferred fuel and purchased power costs — current period	78,277			48,405
Amounts refunded/(charged) to customers	(116,750		)	14,767
Ending balance	$	37,164		$	75,637

Schedule of regulatory assets

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



S		December 31, 2018				December 31, 2017
	Amortization Through	Current		Non-Current		Current		Non-Current
Pension	(a)	$	—	$	733,351	$	—	$	576,188
Retired power plant costs	2033	28,182		167,164		27,402		188,843
Income taxes - AFUDC equity	2048	6,457		151,467		3,828		142,852
Deferred fuel and purchased power — mark-to-market (Note 16)	2023	31,728		23,768		52,100		34,845
Deferred fuel and purchased power (b) (c)	2019	37,164		—		75,637		—
Four Corners cost deferral	2024	8,077		40,228		8,077		48,305
Income taxes — investment tax credit basis adjustment	2047	1,079		25,522		1,066		26,218
Lost fixed cost recovery (b)	2019	32,435		—		59,844		—
Palo Verde VIEs (Note 18)	2046	—		20,015		—		19,395
Deferred compensation	2036	—		36,523		—		36,413
Deferred property taxes	2027	8,569		66,356		8,569		74,926
Loss on reacquired debt	2038	1,637		13,668		1,637		15,305
Tax expense of Medicare subsidy	2024	1,235		6,176		1,236		7,415
TCA balancing account (b)	2020	3,860		772		1,220		—
AG-1 deferral	2022	2,654		5,819		2,654		8,472
Mead-Phoenix transmission line CIAC	2050	332		10,044		332		10,376
Coal reclamation	2026	1,546		15,607		1,068		12,396
SCR deferral	N/A	—		23,276		—		353
Other	Various	1,947		3,185		3,418		—
Total regulatory assets (d)		$	166,902	$	1,342,941	$	248,088	$	1,202,302


(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 7 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.”

Schedule of regulatory liabilities

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



		December 31, 2018				December 31, 2017
	Amortization Through	Current		Non-Current		Current		Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act	(a)	$	—	$	1,272,709	$	—	$	1,266,104
Excess deferred income taxes - FERC - Tax Cuts and Jobs Act	2058	6,302		243,691		—		254,170
Asset retirement obligations	2057	—		278,585		—		332,171
Removal costs	(b)	39,866		177,533		18,238		209,191
Other post retirement benefits	(c)	37,864		125,903		37,642		151,985
Income taxes - deferred investment tax credit	2047	2,164		51,120		2,164		52,497
Income taxes - change in rates	2048	2,769		70,069		2,573		70,537
Spent nuclear fuel	2027	6,503		57,002		6,924		62,132
Renewable energy standard (d)	2020	44,966		20		23,155		—
Demand side management (d)	2020	14,604		4,123		3,066		4,921
Sundance maintenance	2030	1,278		17,228		—		16,897
Deferred gains on utility property	2022	4,423		6,581		4,423		10,988
Four Corners coal reclamation	2038	1,858		17,871		1,858		18,921
Tax expense adjustor mechanism (d)	2019	3,237		—		—		—
Other	Various	42		3,541		43		2,022
Total regulatory liabilities		$	165,876	$	2,325,976	$	100,086	$	2,452,536

(a)

While the majority of the excess deferred tax balance shown is subject to special amortization rules under federal income tax laws, which require amortization of the balance over the remaining regulatory life of the related property, treatment of a portion of the liability, and the month in which pass-through of the excess deferred tax balance will begin is subject to regulatory approval. This approval will be sought through the Company's TEAM adjustor mechanism. As a result, the Company cannot estimate the amount of this regulatory liability which is expected to reverse within the next 12 months. See Note 4.


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


(c)	See Note 7.


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

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of unrecognized tax benefits roll forward

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
	2018			2017			2016			2018			2017			2016
Total unrecognized tax benefits, January 1	$	41,966		$	36,075		$	34,447		$	41,966		$	36,075		$	34,447
Additions for tax positions of the current year	3,436			2,937			2,695			3,436			2,937			2,695
Additions for tax positions of prior years	2,696			4,783			886			2,696			4,783			886
Reductions for tax positions of prior years for:
Changes in judgment	(1,764		)	(1,829		)	(1,953		)	(1,764		)	(1,829		)	(1,953		)
Settlements with taxing authorities	—			—			—			—			—			—
Lapses of applicable statute of limitations	(5,603		)	—			—			(5,603		)	—			—
Total unrecognized tax benefits, December 31	$	40,731		$	41,966		$	36,075		$	40,731		$	41,966		$	36,075

Summary of unrecognized tax benefits

The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):



	Pinnacle West Consolidated							APS Consolidated
	2018			2017		2016		2018			2017		2016
Unrecognized tax benefit interest expense/(benefit) recognized	$	(780	)	$	577	$	529	$	(780	)	$	577	$	529

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
	2018		2017		2016		2018		2017		2016
Unrecognized tax benefit interest accrued	$	1,130	$	1,910	$	1,333	$	1,130	$	1,910	$	1,333

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
	2018		2017		2016		2018		2017		2016
Tax positions, that if recognized, would decrease our effective tax rate	$	19,504	$	16,373	$	11,313	$	19,504	$	16,373	$	11,313

Components of income tax expense

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,
	2018		2017		2016		2018		2017		2016
Current:
Federal	$	18,375	$	11,624	$	8,630	$	88,180	$	21,512	$	711
State	3,342		3,052		1,259		1,877		2,778		4,276
Total current	21,717		14,676		9,889		90,057		24,290		4,987
Deferred:
Federal	94,721		223,729		201,743		32,436		221,078		215,178
State	17,464		19,867		24,779		22,321		23,800		25,677
Total deferred	112,185		243,596		226,522		54,757		244,878		240,855
Income tax expense	$	133,902	$	258,272	$	236,411	$	144,814	$	269,168	$	245,842

Comparison of pretax income from continuing operations at the federal income tax rate to income tax expense - continuing operations

The following chart compares pretax income at the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 to income tax expense (dollars in thousands):



	Pinnacle West Consolidated									APS Consolidated
	Year Ended December 31,									Year Ended December 31,
	2018			2017			2016			2018			2017			2016
Federal income tax expense at statutory rate	$	139,533		$	268,177		$	244,278		$	154,260		$	277,540		$	254,617
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit	16,411			14,897			16,311			19,091			17,276			18,750
Nondeductible expenditures associated with ballot initiative	7,879			—			—			—			—			—
Stock compensation	(1,804		)	(6,659		)	(2,951		)	(780		)	(3,489		)	(1,937		)
Excess deferred income taxes - Tax Cuts and Jobs Act	(6,725		)	9,348			—			(4,715		)	9,431			—
Allowance for equity funds used during construction (see Note 1)	(7,231		)	(12,937		)	(11,724		)	(7,231		)	(12,937		)	(11,724		)
Palo Verde VIE noncontrolling interest (see Note 18)	(4,094		)	(6,823		)	(6,823		)	(4,094		)	(6,823		)	(6,823		)
Investment tax credit amortization	(6,742		)	(6,715		)	(5,887		)	(6,742		)	(6,715		)	(5,887		)
Other	(3,325		)	(1,016		)	3,207			(4,975		)	(5,115		)	(1,154		)
Income tax expense	$	133,902		$	258,272		$	236,411		$	144,814		$	269,168		$	245,842

Components of the net deferred income tax liability

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



	Pinnacle West Consolidated						APS Consolidated
	December 31,						December 31,
	2018			2017			2018			2017
DEFERRED TAX ASSETS
Risk management activities	$	15,785		$	25,103		$	15,785		$	25,103
Regulatory liabilities:
Excess deferred income taxes - Tax Cuts and Jobs Act	376,869			376,906			376,869			376,906
Asset retirement obligation and removal costs	117,201			135,847			117,201			135,847
Unamortized investment tax credits	53,284			54,661			53,284			54,661
Other postretirement benefits	40,532			47,021			40,532			47,021
Other	40,380			37,489			40,380			37,489
Pension liabilities	112,019			83,126			107,009			77,280
Coal reclamation liabilities	47,508			45,802			47,508			45,802
Renewable energy incentives	30,779			33,546			30,779			33,546
Credit and loss carryforwards	1,755			53,946			—			1,920
Other	58,820			56,630			59,919			62,421
Total deferred tax assets	894,932			950,077			889,266			897,996
DEFERRED TAX LIABILITIES
Plant-related	(2,277,724		)	(2,220,886		)	(2,277,724		)	(2,220,886		)
Risk management activities	(237		)	(491		)	(237		)	(491		)
Other postretirement assets and other special use funds	(57,697		)	(66,134		)	(57,274		)	(65,733		)
Regulatory assets:
Allowance for equity funds used during construction	(39,086		)	(36,365		)	(39,086		)	(36,365		)
Deferred fuel and purchased power	(23,086		)	(40,778		)	(23,086		)	(40,778		)
Pension benefits	(181,504		)	(142,848		)	(181,504		)	(142,848		)
Retired power plant costs (see Note 3)	(48,348		)	(53,611		)	(48,348		)	(53,611		)
Other	(72,096		)	(74,423		)	(72,096		)	(74,423		)
Other	(2,575		)	(5,346		)	(2,575		)	(5,346		)
Total deferred tax liabilities	(2,702,353		)	(2,640,882		)	(2,701,930		)	(2,640,481		)
Deferred income taxes — net	$	(1,807,421	)	$	(1,690,805	)	$	(1,812,664	)	$	(1,742,485	)

Lines of Credit and Short-Term Borrowings (Tables)

12 Months Ended

Dec. 31, 2018

Lines of Credit and Short-Term Borrowings

Schedule of consolidated credit facilities and amounts available and outstanding

The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2018 and 2017 (dollars in thousands):



	December 31, 2018								December 31, 2017
	Pinnacle West			APS		Total			Pinnacle West			APS		Total
Commitments under Credit Facilities	$	350,000		$	1,000,000	$	1,350,000		$	325,000		$	1,000,000	$	1,325,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(76,400		)	—		(76,400		)	(95,400		)	—		(95,400		)
Amount of Credit Facilities Available	$	273,600		$	1,000,000	$	1,273,600		$	229,600		$	1,000,000	$	1,229,600

Weighted-Average Commitment Fees	0.125%			0.100%					0.125%			0.100%

Long-Term Debt and Liquidity Matters (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Components of long-term debt on the Consolidated Balance Sheets

The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2018 and 2017 (dollars in thousands):



	Maturity	Interest	December 31,
	Dates (a)	Rates	2018			2017
APS
Pollution control bonds:
Variable	2029	(b)	$	35,975		$	35,975
Fixed	2024	4.70%	115,150			147,150
Total pollution control bonds			151,125			183,125
Senior unsecured notes	2019-2048	2.20%-8.75%	4,575,000			4,275,000
Term loans		(c)	—			150,000
Unamortized discount			(12,638		)	(11,288		)
Unamortized premium			7,736			8,049
Unamortized debt issuance cost			(31,787		)	(31,594		)
Total APS long-term debt			4,689,436			4,573,292
Less current maturities			500,000			82,000
Total APS long-term debt less current maturities			4,189,436			4,491,292
Pinnacle West
Senior unsecured notes	2020	2.25%	300,000			300,000
Term loan	2020	(d)	150,000			—
Unamortized discount			(121		)	(184		)
Unamortized debt issuance cost			(1,083		)	(1,395		)
Total Pinnacle West long-term debt			448,796			298,421
Less current maturities			—			—
Total Pinnacle West long-term debt less current maturities			448,796			298,421
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES			$	4,638,232		$	4,789,713


(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 1.76% at December 31, 2018 and 1.77% at December 31, 2017.


(c)	The weighted-average interest rate was 2.24% at December 31, 2017.


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

Principal payments due on Pinnacle West's and APS's total long-term debt

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
2019	$	500,000	$	500,000
2020	700,000		250,000
2021	—		—
2022	—		—
2023	—		—
Thereafter	3,976,125		3,976,125
Total	$	5,176,125	$	4,726,125

Schedule of estimated fair value of long-term debt, including current maturities

The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):



	As of December 31, 2018				As of December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Pinnacle West	$	448,796	$	443,955	$	298,421	$	298,608
APS	4,689,436		4,789,608		4,573,292		5,006,348
Total	$	5,138,232	$	5,233,563	$	4,871,713	$	5,304,956

Schedule of net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset)

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=114775744&loc=d3e28541-108399

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21506-112644

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
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-URI http://asc.fasb.org/extlink&oid=114775744&loc=d3e28551-108399

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21521-112644

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21538-112644

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=114775985&loc=d3e28878-108400

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21475-112644

+ Details

Retirement Plans and Other Benefits (Tables)

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

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
	2018			2017			2016			2018			2017			2016
Service cost-benefits earned during the period	$	56,669		$	54,858		$	53,792		$	21,100		$	17,119		$	14,993
Interest cost on benefit obligation	124,689			129,756			131,647			28,147			29,959			29,721
Expected return on plan assets	(182,853		)	(174,271		)	(173,906		)	(42,082		)	(53,401		)	(36,495		)
Amortization of:
Prior service cost (credit)	—			81			527			(37,842		)	(37,842		)	(37,883		)
Net actuarial loss	32,082			47,900			40,717			—			5,118			4,589
Net periodic benefit cost (benefit)	$	30,587		$	58,324		$	52,777		$	(30,677	)	$	(39,047	)	$	(25,075	)
Portion of cost charged to expense	$	10,120		$	27,295		$	26,172		$	(21,426	)	$	(18,274	)	$	(12,435	)

Schedule of changes in the benefit obligations and funded status

The following table shows the plans’ changes in the benefit obligations and funded status for the years 2018 and 2017 (dollars in thousands):



	Pension						Other Benefits
	2018			2017			2018			2017
Change in Benefit Obligation
Benefit obligation at January 1	$	3,394,186		$	3,204,462		$	753,393		$	716,445
Service cost	56,669			54,858			21,100			17,119
Interest cost	124,689			129,756			28,147			29,959
Benefit payments	(184,161		)	(166,342		)	(31,540		)	(30,144		)
Actuarial (gain) loss	(200,757		)	171,452			(94,329		)	20,014
Benefit obligation at December 31	3,190,626			3,394,186			676,771			753,393
Change in Plan Assets
Fair value of plan assets at January 1	3,057,027			2,675,357			1,022,371			882,651
Actual return on plan assets	(201,078		)	428,374			(40,354		)	139,367
Employer contributions	50,000			100,000			—			353
Benefit payments	(172,473		)	(146,704		)	(72,453		)	—
Transfer to active union medical account	—			—			(185,887		)	—
Fair value of plan assets at December 31	2,733,476			3,057,027			723,677			1,022,371
Funded Status at December 31	$	(457,150	)	$	(337,159	)	$	46,906		$	268,978

Schedule of projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets

The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets as of December 31, 2018 and 2017 (dollars in thousands):



	2018		2017
Projected benefit obligation	$	3,190,626	$	3,394,186
Accumulated benefit obligation	3,038,774		3,227,233
Fair value of plan assets	2,733,476		3,057,027

Schedule of amounts recognized on the Consolidated Balance Sheets

The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2018 and 2017 (dollars in thousands):



	Pension						Other Benefits
	2018			2017			2018		2017
Noncurrent asset	$	—		$	—		$	46,906	$	268,978
Current liability	(13,980		)	(9,859		)	—		—
Noncurrent liability	(443,170		)	(327,300		)	—		—
Net amount recognized	$	(457,150	)	$	(337,159	)	$	46,906	$	268,978

Schedule of accumulated other comprehensive loss

The following table shows the details related to accumulated other comprehensive loss as of December 31, 2018 and 2017 (dollars in thousands):



	Pension						Other Benefits
	2018			2017			2018			2017
Net actuarial loss	$	794,292		$	643,199		$	63,544		$	75,439
Prior service credit	—			—			(227,733		)	(265,575		)
APS’s portion recorded as a regulatory (asset) liability	(733,351		)	(576,188		)	163,767			189,627
Income tax expense (benefit)	(15,083		)	(24,915		)	561			853
Accumulated other comprehensive loss	$	45,858		$	42,096		$	139		$	344

Schedule of estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost

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 2019 (dollars in thousands):



	Pension		Other Benefits
Net actuarial loss	$	43,248	$	—
Prior service credit	—		(37,821		)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2019	$	43,248	$	(37,821	)

Schedule of weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs

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,
	2018		2017		2018		2017		2016
Discount rate – pension	4.34	%	3.65	%	3.65	%	4.08	%	4.37	%
Discount rate – other benefits	4.39	%	3.71	%	3.71	%	4.17	%	4.52	%
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		6.05	%	6.55	%	6.90	%
Expected long-term return on plan assets - other benefits	N/A		N/A		5.40	%	6.05	%	4.45	%
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	%	5.00	%	5.00	%
Ultimate healthcare cost trend rate	4.75	%	4.75	%	4.75	%	5.00	%	5.00	%
Number of years to ultimate trend rate (pre-65 participants)	7		8		8		4		4

Schedule of effects of one percentage point change in the assumed initial and ultimate health care cost trend rates

A one percentage point change in the assumed initial and ultimate healthcare cost trend rates would have the following effects on our December 31, 2018 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	$	10,235	$	(4,322	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	11,223		(8,479		)
Effect on the accumulated other postretirement benefit obligation	101,224		(81,144		)

Schedule of fair value of pension plan and other postretirement benefit plan assets, by asset category

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



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2018
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 net asset value 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.

Based on the IPS, and given the pension plan's funded status at year-end 2018, the target and actual allocation for the pension plan at December 31, 2018 are as follows:



	Pension
	Target Allocation		Actual Allocation
Long-term fixed income assets	62	%	64	%
Return-generating assets	38	%	36	%
Total	100	%	100	%

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

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



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

The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2018:



	Other Benefits
	Actual Allocation
Long-term fixed income assets	69	%
Return-generating assets	31	%
Total	100	%

The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2017, by asset category, are as follows (dollars in thousands):



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Other (a)		Balance at December 31, 2017
Pension Plan:
Cash and cash equivalents	$	3,830	$	—	$	—	$	3,830
Fixed income securities:
Corporate	—		1,365,194		—		1,365,194
U.S. Treasury	221,291		—		—		221,291
Other (b)	—		100,599		—		100,599
Common stock equities (c)	228,088		—		—		228,088
Mutual funds (d)	233,732		—		—		233,732
Common and collective trusts:
Equities	—		—		408,763		408,763
Real estate	—		—		171,569		171,569
Fixed Income	—		—		90,869		90,869
Partnerships	—		—		133,379		133,379
Short-term investments and other (e)	—		1,208		98,505		99,713
Total	$	686,941	$	1,467,001	$	903,085	$	3,057,027
Other Benefits:
Cash and cash equivalents	$	143	$	—	$	—	$	143
Fixed income securities:
Corporate	—		306,008		—		306,008
U.S. Treasury	336,963		—		—		336,963
Other (b)	—		32,508		—		32,508
Common stock equities (c)	196,153		—		—		196,153
Mutual funds (d)	39,269		—		—		39,269
Common and collective trusts:
Equities	—		—		75,310		75,310
Real estate	—		—		15,422		15,422
Short-term investments and other (e)	11,268		149		9,178		20,595
Total	$	583,796	$	338,665	$	99,910	$	1,022,371


(a)	These investments primarily represent assets valued using net asset value 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.

Schedule of estimated future benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter

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
2019	$	188,492	$	32,622
2020	193,087		34,199
2021	198,471		35,551
2022	204,399		36,673
2023	211,346		37,405
Years 2024-2028	1,093,319		187,023

Leases (Tables)

12 Months Ended

Dec. 31, 2018

Leases [Abstract]

Estimated future minimum lease payments for Pinnacle West's and APS's operating leases, excluding purchased power agreements

Estimated future minimum lease payments for Pinnacle West’s and APS’s operating leases, excluding purchased power agreements, are approximately as follows (dollars in thousands):



Year	Pinnacle West Consolidated		APS
2019	$	13,747	$	13,411
2020	12,428		12,143
2021	9,478		9,282
2022	6,513		6,321
2023	5,359		5,171
Thereafter	42,236		40,656
Total future lease commitments	$	89,761	$	86,984

Jointly-Owned Facilities (Tables)

12 Months Ended

Dec. 31, 2018

Jointly Owned Utility Plant, Net Ownership Amount [Abstract]

APS's interests in jointly-owned facilities recorded on the Consolidated Balance Sheets

The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2018 (dollars in thousands):



	Percent Owned			Plant in Service		Accumulated Depreciation		Construction Work in Progress
Generating facilities:
Palo Verde Units 1 and 3	29.1	%		$	1,887,729	$	1,095,878	$	25,185
Palo Verde Unit 2 (a)	16.8	%		638,419		369,372		20,852
Palo Verde Common	28.0	%	(b)	752,300		277,414		39,995
Palo Verde Sale Leaseback			(a)	351,050		245,275		—
Four Corners Generating Station	63.0	%		1,466,579		544,308		23,430
Cholla common facilities (c)	50.5	%		183,390		82,434		893
Transmission facilities:
ANPP 500kV System	33.5	%	(b)	129,587		49,340		2,705
Navajo Southern System	26.7	%	(b)	82,046		30,464		284
Palo Verde — Yuma 500kV System	19.0	%	(b)	15,304		6,729		530
Four Corners Switchyards	63.1	%	(b)	68,707		15,436		1,334
Phoenix — Mead System	17.1	%	(b)	39,329		18,527		44
Palo Verde — Rudd 500kV System	50.0	%		93,887		25,573		302
Morgan — Pinnacle Peak System	64.6	%	(b)	117,722		16,744		—
Round Valley System	50.0	%		515		153		—
Palo Verde — Morgan System	87.9	%	(b)	219,292		6,660		—
Hassayampa — North Gila System	80.0	%		142,541		9,805		—
Cholla 500kV Switchyard	85.7	%		5,078		1,414		38
Saguaro 500kV Switchyard	60.0	%		20,414		12,790		—
Kyrene — Knox System	50.0	%		578		307		—


(a)	See Note 18.


(b)	Weighted-average of interests.

(c)

PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Summary of estimated coal take-or-pay commitments

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



	Years Ended December 31,
	2019		2020		2021		2022		2023		Thereafter
Coal take-or-pay commitments (a)	$	179,879	$	181,059	$	184,944	$	186,244	$	187,518	$	1,422,253

(a)

Total take-or-pay commitments are approximately $2.3 billion. The total net present value of these commitments is approximately $1.7 billion.

Summary of actual take-or-pay commitments

The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):



	Year Ended December 31,
	2018		2017		2016
Total purchases	$	206,093	$	165,220	$	160,066

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Change in asset retirement obligations

The following table shows the change in our asset retirement obligations for 2018 and 2017 (dollars in thousands):



	2018			2017
Asset retirement obligations at the beginning of year	$	679,529		$	624,475
Changes attributable to:
Accretion expense	36,876			33,104
Settlements	(9,726		)	—
Estimated cash flow revisions	2,002			21,950
Newly incurred or acquired obligations	17,864			—
Asset retirement obligations at the end of year	$	726,545		$	679,529

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Selected Quarterly Financial Information [Line Items]

Schedule of quarterly financial information

Consolidated quarterly financial information for 2018 and 2017 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.



	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



	2017 Quarter Ended								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,728	$	944,587	$	1,183,322	$	759,659	$	3,565,296
Operations and maintenance	226,071		220,985		230,839		271,212		949,107
Operating income	67,411		297,257		459,548		85,547		909,763
Income taxes	4,211		88,967		144,319		20,775		258,272
Net income	28,185		172,317		280,945		26,502		507,949
Net income attributable to common shareholders	23,312		167,443		276,072		21,629		488,456

Earnings Per Share:
Net income attributable to common shareholders — Basic	$	0.21	$	1.50	$	2.47	$	0.19	$	4.37
Net income attributable to common shareholders — Diluted	0.21		1.49		2.46		0.19		4.35

Selected Quarterly Financial Information [Line Items]

Schedule of quarterly financial information

APS's quarterly financial information for 2018 and 2017 is as follows (dollars in thousands):



	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



	2017 Quarter Ended								2017
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	677,589	$	943,406	$	1,178,846	$	757,811	$	3,557,652
Operations and maintenance	219,008		215,775		222,374		260,826		917,983
Operating income	70,269		296,700		465,658		91,912		924,539
Net income attributable to common shareholder	23,162		169,108		284,256		27,783		504,309

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair value of assets and liabilities that are measured at fair value on a recurring basis

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



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Other				Balance at December 31, 2018
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 debt 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.


(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.

The following table presents the fair value at December 31, 2017 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):



	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (a) (Level 3)			Other				Balance at December 31, 2017
Assets
Cash equivalents	$	10,630	$	—		$	—		$	—			$	10,630
Risk management activities — derivative instruments:
Commodity contracts	—		5,683			1,036			(4,737		)	(b)	1,982
Nuclear decommissioning trust:
Cash and cash equivalents	7,224		—			—			109			(d)	7,333
U.S. commingled equity funds	—		—			—			417,390			(e)	417,390
U.S. Treasury debt	127,662		—			—			—				127,662
Corporate debt	—		114,007			—			—				114,007
Mortgage-backed debt securities	—		111,874			—			—				111,874
Municipal bonds	—		79,049			—			—				79,049
Other fixed income	—		13,685			—			—				13,685
Subtotal nuclear decommissioning trust	134,886		318,615			—			417,499				871,000

Other special use funds (c):	455		31,562			—			525				32,542

Total Assets	$	145,971	$	355,860		$	1,036		$	413,287			$	916,154
Liabilities
Risk management activities — derivative instruments:
Commodity contracts	$	—	$	(78,646	)	$	(19,292	)	$	1,516		(b)	$	(96,422	)


(a)	Primarily consists of long-dated electricity contracts.


(b)	Represents counterparty netting, margin, and collateral. See Note 16.


(c)	Primarily consists of fixed income municipal bonds. Presented as coal reclamation escrow in 2017.


(d)	Represents nuclear decommissioning trust net pending securities sales and purchases.

(e)

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

Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments

The following tables provide information regarding our significant unobservable inputs used to value our risk management derivative Level 3 instruments at December 31, 2018 and December 31, 2017:



	December 31, 2018 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
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.



	December 31, 2017 Fair Value (thousands)				Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Range	Weighted-Average
Electricity:
Forward Contracts (a)	$	21	$	15,485	Discounted cash flows	Electricity forward price (per MWh)	$18.51 - $38.75	$	27.89
Natural Gas:
Forward Contracts (a)	1,015		3,807		Discounted cash flows	Natural gas forward price (per MMBtu)	$2.33 - $3.11	$	2.71
Total	$	1,036	$	19,292


(a)	Includes swaps and physical and financial contracts.

Changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs

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, 2018 and 2017 (dollars in thousands):



	Year Ended December 31,
Commodity Contracts	2018			2017
Net derivative balance at beginning of period	$	(18,256	)	$	(47,406	)
Total net gains (losses) realized/unrealized:
Included in earnings	—			—
Included in OCI	—			3
Deferred as a regulatory asset or liability	(1,130		)	(13,643		)
Settlements	(787		)	5,834
Transfers into Level 3 from Level 2	(12,830		)	(10,026		)
Transfers from Level 3 into Level 2	24,789			46,982
Net derivative balance at end of period	$	(8,214	)	$	(18,256	)
Net unrealized gains included in earnings related to instruments still held at end of period	$	—		$	—

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Schedule of earnings per weighted average common share outstanding

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, 2018, 2017 and 2016 (in thousands, except per share amounts):



	2018		2017		2016
Net income attributable to common shareholders	$	511,047	$	488,456	$	442,034
Weighted average common shares outstanding — basic	112,129		111,839		111,409
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units	421		528		637
Weighted average common shares outstanding — diluted	112,550		112,367		112,046
Earnings per weighted-average common share outstanding
Net income attributable to common shareholders - basic	$	4.56	$	4.37	$	3.97
Net Income attributable to common shareholders - diluted	$	4.54	$	4.35	$	3.95

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Nonvested Restricted Stock, Stock Grants and Stock Units

The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2018, 2017 and 2016:



	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2018		2017		2016		2018		2017		2016
Units granted	132,997		161,963		141,811		171,708		147,706		166,666
Weighted-average grant date fair value	$	77.51	$	72.60	$	67.34	$	76.56	$	78.99	$	66.60


(a)	Units granted includes awards that will be cash settled of 66,252 in 2018, 67,599 in 2017, and 43,952 in 2016.

(b)

Reflects the target payout level.The following table is a summary of the status of non-vested awards as of December 31, 2018 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, 2018	291,288			$	69.78	309,502		$	72.46
Granted	132,997			77.51		171,708		76.56
Vested	(147,938	)		67.12		(159,284	)	66.61
Forfeited (c)	(5,356	)		73.42		(9,542	)	73.34
Nonvested at December 31, 2018	270,991		(a)	74.39		312,384		77.67
Vested Awards Outstanding at December 31, 2018	73,144					159,284


(a)	Includes 148,131 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.

Summary of Nonvested Performance Shares

The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2018, 2017 and 2016:



	Restricted Stock Units, Stock Grants, and Stock Units (a)						Performance Shares (b)
	2018		2017		2016		2018		2017		2016
Units granted	132,997		161,963		141,811		171,708		147,706		166,666
Weighted-average grant date fair value	$	77.51	$	72.60	$	67.34	$	76.56	$	78.99	$	66.60


(a)	Units granted includes awards that will be cash settled of 66,252 in 2018, 67,599 in 2017, and 43,952 in 2016.

(b)

Reflects the target payout level.The following table is a summary of the status of non-vested awards as of December 31, 2018 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, 2018	291,288			$	69.78	309,502		$	72.46
Granted	132,997			77.51		171,708		76.56
Vested	(147,938	)		67.12		(159,284	)	66.61
Forfeited (c)	(5,356	)		73.42		(9,542	)	73.34
Nonvested at December 31, 2018	270,991		(a)	74.39		312,384		77.67
Vested Awards Outstanding at December 31, 2018	73,144					159,284


(a)	Includes 148,131 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.

Derivative Accounting (Tables)

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding gross notional amount of derivatives, which represents both purchases and sales (does not reflect net position)

As of December 31, 2018 and 2017, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):



		Quantity
Commodity	Unit of Measure	December 31, 2018	December 31, 2017
Power	GWh	250	583
Gas	Billion cubic feet	218	240

Gains and losses from derivative instruments in designated cash flow accounting hedges relationships

The following table provides information about gains and losses from derivative instruments in designated cash flow accounting hedging relationships during the years ended December 31, 2018, 2017 and 2016 (dollars in thousands):



	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2018			2017			2016
Gain (Loss) Recognized in OCI on Derivative Instruments (Effective Portion)	OCI — derivative instruments	$	—		$	(59	)	$	47
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)	Fuel and purchased power (b)	(2,000		)	(3,519		)	(3,926		)


(a)	During the years ended December 31, 2018, 2017, and 2016, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

(b)

Amounts are before the effect of PSA deferrals.

Gains and losses from derivative instruments not designated as accounting hedges instruments

The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments during the years ended December 31, 2018, 2017 and 2016 (dollars in thousands):



	Financial Statement	Year Ended December 31,
Commodity Contracts	Location	2018			2017			2016
Net Gain (Loss) Recognized in Income	Operating revenues	$	(2,557	)	$	(1,192	)	$	771
Net Gain (Loss) Recognized in Income	Fuel and purchased power (a)	(12,951		)	(87,991		)	25,711
Total		$	(15,508	)	$	(89,183	)	$	26,482

(a)

Amounts are before the effect of PSA deferrals.

Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts on offsetting liabilities

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, 2018 and 2017. 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, 2018: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	3,106		$	(2,149	)	$	957		$	156		$	1,113
Investments and other assets	36			(36		)	—			—			—
Total assets	3,142			(2,185		)	957			156			1,113

Current liabilities	(36,345		)	2,149			(34,196		)	(1,310		)	(35,506		)
Deferred credits and other	(24,567		)	36			(24,531		)	—			(24,531		)
Total liabilities	(60,912		)	2,185			(58,727		)	(1,310		)	(60,037		)
Total	$	(57,770	)	$	—		$	(57,770	)	$	(1,154	)	$	(58,924	)


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


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


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



As of December 31, 2017: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	5,427		$	(3,796	)	$	1,631		$	300		$	1,931
Investments and other assets	1,292			(1,241		)	51			—			51
Total assets	6,719			(5,037		)	1,682			300			1,982

Current liabilities	(59,527		)	3,796			(55,731		)	(3,521		)	(59,252		)
Deferred credits and other	(38,411		)	1,241			(37,170		)	—			(37,170		)
Total liabilities	(97,938		)	5,037			(92,901		)	(3,521		)	(96,422		)
Total	$	(91,219	)	$	—		$	(91,219	)	$	(3,221	)	$	(94,440	)


(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 $3,521 and cash margin provided to counterparties of $300.

Schedule of the entity's fair value of risk management activities reported on a gross basis and the impacts on offsetting assets

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, 2018 and 2017. 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, 2018: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	3,106		$	(2,149	)	$	957		$	156		$	1,113
Investments and other assets	36			(36		)	—			—			—
Total assets	3,142			(2,185		)	957			156			1,113

Current liabilities	(36,345		)	2,149			(34,196		)	(1,310		)	(35,506		)
Deferred credits and other	(24,567		)	36			(24,531		)	—			(24,531		)
Total liabilities	(60,912		)	2,185			(58,727		)	(1,310		)	(60,037		)
Total	$	(57,770	)	$	—		$	(57,770	)	$	(1,154	)	$	(58,924	)


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


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


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



As of December 31, 2017: (dollars in thousands)	Gross Recognized Derivatives (a)			Amounts Offset (b)			Net Recognized Derivatives			Other (c)			Amount Reported on Balance Sheet
Current assets	$	5,427		$	(3,796	)	$	1,631		$	300		$	1,931
Investments and other assets	1,292			(1,241		)	51			—			51
Total assets	6,719			(5,037		)	1,682			300			1,982

Current liabilities	(59,527		)	3,796			(55,731		)	(3,521		)	(59,252		)
Deferred credits and other	(38,411		)	1,241			(37,170		)	—			(37,170		)
Total liabilities	(97,938		)	5,037			(92,901		)	(3,521		)	(96,422		)
Total	$	(91,219	)	$	—		$	(91,219	)	$	(3,221	)	$	(94,440	)


(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 $3,521 and cash margin provided to counterparties of $300.

Information about derivative instruments that have credit-risk-related contingent features

The following table provides information about our derivative instruments that have credit-risk-related contingent features at December 31, 2018 (dollars in thousands):



	December 31, 2018
Aggregate fair value of derivative instruments in a net liability position	$	60,912
Cash collateral posted	—
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)	56,876

(a)

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

Other Income and Other Expense (Tables)

12 Months Ended

Dec. 31, 2018

Component of Other Income and Other Expense Nonoperating [Line Items]

Detail of other income and other expense

The following table provides detail of Pinnacle West's Consolidated other income and other expense for 2018, 2017 and 2016 (dollars in thousands):



	2018			2017			2016
Other income:
Interest income	$	8,647		$	3,497		$	884
Debt return on Four Corners SCR deferral (Note 3)	16,153			354			—
Miscellaneous	96			155			17
Total other income	$	24,896		$	4,006		$	901
Other expense:
Non-operating costs	$	(10,076	)	$	(11,749	)	$	(9,235	)
Investment losses — net	(417		)	(4,113		)	(1,747		)
Miscellaneous	(7,473		)	(5,677		)	(4,355		)
Total other expense	$	(17,966	)	$	(21,539	)	$	(15,337	)

Component of Other Income and Other Expense Nonoperating [Line Items]

Detail of other income and other expense

The following table provides detail of APS’s other income and other expense for 2018, 2017 and 2016 (dollars in thousands):



	2018			2017			2016
Other income:
Interest income	$	6,496		$	2,504		$	261
Debt return on Four Corners SCR deferral (Note 3)	16,153			354			—
Miscellaneous	97			155			10
Total other income	$	22,746		$	3,013		$	271
Other expense:
Non-operating costs	$	(9,462	)	$	(10,825	)	$	(8,455	)
Miscellaneous	(5,830		)	(3,088		)	(2,099		)
Total other expense	$	(15,292	)	$	(13,913	)	$	(10,554	)

Palo Verde Sale Leaseback Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2018

Variable Interest Entities [Abstract]

Amounts relating to the VIEs included in Consolidated Balance Sheets

Our Consolidated Balance Sheets at December 31, 2018 and December 31, 2017 include the following amounts relating to the VIEs (dollars in thousands):



	December 31, 2018		December 31, 2017
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation	$	105,775	$	109,645
Equity-Noncontrolling interests	125,790		129,040

Investments, Debt and Equity Securities [Abstract]

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

Investments in Nuclear Decommissioning Trusts and Other Special Use Funds (Tables)

12 Months Ended

Dec. 31, 2018

Fair value of APS's nuclear decommissioning trust fund assets

The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS's nuclear decommissioning trust and other special use fund assets at December 31, 2018 and December 31, 2017 (dollars in thousands):



	December 31, 2018
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total			Total Unrealized Gains		Total Unrealized Losses
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.



	December 31, 2017
	Fair Value							Total Unrealized Gains		Total Unrealized Losses
Investment Type:	Nuclear Decommissioning Trusts		Other Special Use Funds		Total			Total Unrealized Gains		Total Unrealized Losses
Equity Securities	$	424,614	$	430	$	425,044		$	248,623	$	—
Available for Sale-Fixed Income Securities	446,277		29,439		475,716		(a)	11,537		(2,996		)
Other	109		489		598		(b)	—		—
Total	$	871,000	$	30,358	$	901,358		$	260,160	$	(2,996	)


(a)	As of December 31, 2017, the amortized cost basis of these available-for-sale investments is $467 million.

(b)

Represents net pending securities sales and purchases.

Realized gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds

following table sets forth APS's realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the years ended December 31, 2018, 2017 and 2016 (dollars in thousands):



	Year Ended December 31,
	Nuclear Decommissioning Trusts			Other Special Use Funds			Total
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
2016
Realized gains	11,213			—			11,213
Realized losses	(10,106		)	—			(10,106		)
Proceeds from the sale of securities (a)	633,410			—			633,410


(a)	Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds.

Fair value of fixed income securities, summarized by contractual maturities

The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2018 is as follows (dollars in thousands):



	Nuclear Decommissioning		Coal Reclamation Escrow Accounts		Active Union Medical Trust		Total
Less than one year	$	26,819	$	21,237	$	39,966	$	88,022
1 year – 5 years	97,566		15,658		104,128		217,352
5 years – 10 years	128,379		2,511		—		130,890
Greater than 10 years	194,214		6,878		—		201,092
Total	$	446,978	$	46,284	$	144,094	$	637,356

Revenue (Tables)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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



	Year Ended December 31,
	2018
Retail residential electric service	$	1,867,370
Retail non-residential electric service	1,628,891
Wholesale energy sales	109,198
Transmission services for others	60,261
Other sources	25,527
Total operating revenues	$	3,691,247

Changes in Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2018

Changes in accumulated other comprehensive income (loss) including reclassification adjustments, by component:

Schedule of changes in accumulated other comprehensive loss including reclassification adjustments, by component

The following table shows the changes in Pinnacle West's consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2018 and 2017 (dollars in thousands):



	Pension and Other Postretirement Benefits				Derivative Instruments				Total
Balance December 31, 2016	$	(39,070	)		$	(4,752	)		$	(43,822	)
OCI (loss) before reclassifications	(6,438		)		(35		)		(6,473		)
Amounts reclassified from accumulated other comprehensive loss	3,068			(a)	2,225			(b)	5,293
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	)


(a)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost. See Note 7.

(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.

Summary of Significant Accounting Policies - Narrative (Details) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended			36 Months Ended
	May 31, 2014 $ / kWh	Dec. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2017	Jul. 06, 2016
Approximate remaining average useful lives of utility property
Depreciation		$ 486	$ 453	$ 422
Depreciation rates (as a percent)		2.81%	2.80%	2.66%
Allowance for Funds Used During Construction
Composite rate used to calculate AFUDC (as a percent)		7.03%	6.68%	7.17%
Income Taxes
Percent likelihood largest tax benefit amount is realized (greater than)		50.00%
Intangible Assets
Amortization expense		$ 68	$ 72	$ 58
Estimated amortization expense on existing intangible assets over the next five years
2019		58
2020		47
2021		34
2022		25
2023		$ 22
Remaining amortization period for intangible assets		8 years
Pinnacle West
Preferred Stock
Preferred stock, shares authorized (in shares) \| shares		10,000,000
ARIZONA PUBLIC SERVICE COMPANY
Nuclear Fuel
Charges for the permanent disposal of spent nuclear fuel (in dollars per kWh) \| $ / kWh	0.001
Preferred Stock
Preferred stock, shares authorized (in shares) \| shares		15,535,000
Preferred stock par or stated value per share 1 (in dollars per share) \| $ / shares		$ 25
Preferred stock par or stated value per share 2 (in dollars per share) \| $ / shares		50
Preferred stock par or stated value per share 3 (in dollars per share) \| $ / shares		$ 100
Minimum
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)					0.18%
Maximum
Approximate remaining average useful lives of utility property
Depreciation rates (as a percent)					19.67%
Investments
Ownership percentage for classification as cost method investments by El Dorado		20.00%
Fossil plant
Approximate remaining average useful lives of utility property
Average useful life		17 years
Nuclear plant
Approximate remaining average useful lives of utility property
Average useful life		23 years
Other generation
Approximate remaining average useful lives of utility property
Average useful life		19 years
Transmission
Approximate remaining average useful lives of utility property
Average useful life		39 years
Distribution
Approximate remaining average useful lives of utility property
Average useful life		34 years
General plant
Approximate remaining average useful lives of utility property
Average useful life		6 years
El Paso's Interest in Four Corners \| 4CA
Utility Plant and Depreciation [Line Items]
Ownership interest acquired (as a percent)		7.00%				7.00%

Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Utility Plant and Depreciation [Line Items]
Depreciation and amortization	$ 582,354	$ 534,118	$ 485,829
Net	12,370,614	11,669,526
Construction work in progress	1,170,062	1,291,498
Palo Verde sale leaseback, net of accumulated depreciation	105,775	109,645
Intangible assets, net of accumulated amortization	262,902	257,189
Nuclear fuel, net of accumulated amortization	120,217	117,408
Total property, plant and equipment	14,029,570	13,445,266
Electric Service
Utility Plant and Depreciation [Line Items]
Generation	8,285,514	7,963,998
Transmission	3,033,579	2,836,578
Distribution	6,378,345	6,025,856
General plant	1,039,190	971,629
Plant in service and held for future use	18,736,628	17,798,061
Accumulated depreciation and amortization	(6,366,014)	(6,128,535)
Net	12,370,614	11,669,526
Construction work in progress	1,170,062	1,291,498
Palo Verde sale leaseback, net of accumulated depreciation	105,775	109,645
Intangible assets, net of accumulated amortization	262,902	257,189
Nuclear fuel, net of accumulated amortization	120,217	117,408
Total property, plant and equipment	$ 14,029,570	$ 13,445,266

Summary of Significant Accounting Policies - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Income tax (benefit), net of refunds	$ 21,173	$ 2,186	$ 9,956
Interest, net of amounts capitalized	208,479	189,288	184,462
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Accrued capital expenditures	132,620	130,404	114,855
Dividends declared but not paid	82,675	77,667	72,926
Sale of 4CA 7% interest in Four Corners	$ 68,907	$ 0	$ 0

New Accounting Standards (Details) - USD ($) $ in Thousands			12 Months Ended
New Accounting Standards (Details) - USD ($) $ in Thousands	Jul. 03, 2018	Jul. 06, 2016	Dec. 31, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of income tax effects related to new tax reform (See Note 2)			$ (8,552)
Right-of-use lease assets			194,000
Lease, cost			119,000
Other			129,312	$ 130,666
Other current liabilities			184,229	246,529
Accounting Standards Update 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net benefit costs capitalized			(15,000)
Accounting Standards Update 2018-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of income tax effects related to new tax reform (See Note 2)			9,000
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Other			(85,000)
Other current liabilities			(10,000)
ARIZONA PUBLIC SERVICE COMPANY
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of income tax effects related to new tax reform (See Note 2)			(5,038)
Other			128,265	129,801
Other current liabilities			178,137	$ 243,922
ARIZONA PUBLIC SERVICE COMPANY \| Accounting Standards Update 2018-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of income tax effects related to new tax reform (See Note 2)			$ 5,000
Four Corners \| 4CA
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Percentage share cost of control	7.00%	7.00%

Regulatory Matters - Retail Rate Case Filing (Details) - Retail Rate Case Filing with Arizona Corporation Commission - ACC - ARIZONA PUBLIC SERVICE COMPANY	Jan. 03, 2018 Customer	Nov. 13, 2017 USD ($)	Mar. 27, 2017 USD ($) $ / kWh	Mar. 26, 2017 $ / kWh	Jun. 01, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jun. 01, 2011 USD ($)
Public Utilities, General Disclosures [Line Items]
Net retail rate increase					$ 165,900,000		$ 95,500,000
Adjuster account balance transferred into base rates						$ 267,600,000
Approximate percentage of increase in average customer bill			3.28%		5.74%
Approximate percentage of increase in average residential customer bill			4.54%		7.96%
Settlement agreement, net retail base rate increase			$ 94,600,000
Settlement agreement, non-fuel, non-depreciation, base rate increase			87,200,000
Fuel-related base rate decrease			53,600,000
Base rate increase, changes in depreciation schedules			$ 61,000,000.0
Authorized return on common equity (as a percent)			10.00%
Percentage of debt in capital structure			44.20%
Percentage of common equity in capital structure			55.80%
Environmental surcharge cap rate (in dollars per kWh) \| $ / kWh			0.00050	0.00016
Resource comparison proxy for exported energy (in dollars per kWh) \| $ / kWh			0.129
Monthly metering infrastructure opt-out fee		$ 5
Number of customers which signed complaint \| Customer	25
AZ Sun II Program
Public Utilities, General Disclosures [Line Items]
Minimum annual renewable energy standard and tariff			$ 10,000,000
Maximum annual renewable energy standard and tariff			$ 15,000,000

Regulatory Matters - Narrative (Details)																						1 Months Ended	12 Months Ended
Regulatory Matters - Narrative (Details)	Feb. 15, 2019 USD ($)	Feb. 01, 2019 $ / kWh	Aug. 13, 2018 USD ($)	Jun. 01, 2018 USD ($)	May 01, 2018 $ / kWh	Feb. 22, 2018 USD ($)	Feb. 20, 2018	Feb. 15, 2018 USD ($)	Feb. 01, 2018 $ / kWh	Jan. 08, 2018 USD ($)	Nov. 20, 2017 USD ($)	Aug. 19, 2017 $ / kWh	Jun. 01, 2017 USD ($)	Feb. 01, 2017 $ / kWh	Jan. 13, 2017 USD ($)	Dec. 20, 2016 $ / kWh	Jun. 01, 2016 USD ($)	Feb. 01, 2016 $ / kWh	Jan. 15, 2016 USD ($)	Feb. 01, 2015 $ / kWh	Jun. 01, 2011 USD ($)	Dec. 31, 2014 penetration_feeder storage_system MW	Dec. 31, 2018 USD ($) $ / kWh	Dec. 31, 2017 USD ($)	Dec. 31, 2012 $ / kWh	Jun. 29, 2018 USD ($)	Nov. 14, 2017 USD ($)	Sep. 01, 2017 USD ($)	Jun. 30, 2017 USD ($)	Jan. 27, 2017 USD ($)	Jul. 01, 2016 USD ($)	Nov. 25, 2015 USD ($)	Mar. 20, 2015 project
Regulatory Matters [Line Items]
Ballot initiative, proposed required energy supply to be obtained from renewable sources (as a percent)							50.00%
ARIZONA PUBLIC SERVICE COMPANY
Regulatory Matters [Line Items]
Requested rate decrease for tax act																								$ (377,000,000)
ARIZONA PUBLIC SERVICE COMPANY \| Lost Fixed Cost Recovery Mechanism
Regulatory Matters [Line Items]
Fixed costs recoverable per residential power lost (in dollars per kWh) \| $ / kWh																									0.031
Fixed costs recoverable per non-residential power lost (in dollars per kWh) \| $ / kWh																									0.023
Fixed costs recoverable per power lost (in dollars per kWh) \| $ / kWh																							0.025
Rate matter cap percentage of retail revenue																							1.00%
Amount of adjustment approved representing prorated sales losses															$ 63,700,000				$ 46,400,000
Increase in amount of adjustment representing prorated sales losses															$ 17,300,000				$ 7,900,000
Amount of adjustment approved representing prorated sales losses pending approval								$ 60,700,000
Decrease in amount of adjustment representing prorated sales losses								$ 3,000,000
ARIZONA PUBLIC SERVICE COMPANY \| ACC
Regulatory Matters [Line Items]
Requested rate decrease for tax act			$ 86,500,000							$ 119,100,000
Approved rate decrease for tax act						$ 119,100,000
ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Retail Rate Case Filing with Arizona Corporation Commission
Regulatory Matters [Line Items]
Net retail rate increase																	$ 165,900,000				$ 95,500,000
ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Arizona Renewable Energy Standard and Tariff 2017
Regulatory Matters [Line Items]
Amount of approved budget																															$ 150,000,000
ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Arizona Renewable Energy Standard and Tariff 2018
Regulatory Matters [Line Items]
Amount of proposed budget																										$ 89,900,000			$ 90,000,000
ARIZONA PUBLIC SERVICE COMPANY \| ACC \| 2015 DSMAC
Regulatory Matters [Line Items]
Amount of approved budget																																$ 68,900,000
Rate matter number of resource savings projects \| project																																	3
ARIZONA PUBLIC SERVICE COMPANY \| ACC \| 2017 DSMAC
Regulatory Matters [Line Items]
Amount of proposed budget																	$ 62,600,000
Amount of approved budget																														$ 66,600,000
ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Demand Side Management Adjustor Charge 2018
Regulatory Matters [Line Items]
Amount of proposed budget																							$ 34,100,000				$ 52,600,000	$ 52,600,000
ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Power Supply Adjustor (PSA)
Regulatory Matters [Line Items]
Maximum increase (decrease) in PSA rate (in dollars per kWh) \| $ / kWh									0.004
Fuel And purchased power costs, excess annual limit																							$ 16,400,000
PSA rate (in dollars per kWh) \| $ / kWh									0.004555			0.000555		(0.001348)
Forward component of PSA rate (in dollars per kWh) \| $ / kWh									0.002009			0.000876		(0.001027)
Historical component of PSA rate (in dollars per kWh) \| $ / kWh									0.002546			(0.000321)		(0.000321)
ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Net Metering
Regulatory Matters [Line Items]
Cost of service, resource comparison proxy method, maximum annual percentage decrease																10.00%
Cost of service for interconnected DG system customers, grandfathered period																20 years
Guaranteed export price period																10 years
Settlement agreement, energy price for exported energy (in dollars per kWh) \| $ / kWh																0.129
Request second-year energy price for exported energy \| $ / kWh					0.116
ARIZONA PUBLIC SERVICE COMPANY \| FERC \| Transmission rates, transmission cost adjustor and other transmission matters
Regulatory Matters [Line Items]
Increase (decrease) in annual wholesale transmission rates													$ 35,100,000
Rate Matters, Increase (Decrease) in Cost Recovery				$ (22,700,000)
Cost Recovery Mechanisms \| ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Power Supply Adjustor (PSA)
Regulatory Matters [Line Items]
Maximum increase (decrease) in PSA rate (in dollars per kWh) \| $ / kWh																				0.004
PSA Rate in Prior Years (decrease) \| $ / kWh																		0.001678
Subsequent Event \| ARIZONA PUBLIC SERVICE COMPANY \| Lost Fixed Cost Recovery Mechanism
Regulatory Matters [Line Items]
Amount of adjustment approved representing prorated sales losses pending approval	$ 36,200,000
Decrease in amount of adjustment representing prorated sales losses	$ 24,500,000
Subsequent Event \| ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Power Supply Adjustor (PSA)
Regulatory Matters [Line Items]
PSA rate (in dollars per kWh) \| $ / kWh		0.001658
Forward component of PSA rate (in dollars per kWh) \| $ / kWh		0.000536
Historical component of PSA rate (in dollars per kWh) \| $ / kWh		0.001122
Subsequent Event \| Cost Recovery Mechanisms \| ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Power Supply Adjustor (PSA)
Regulatory Matters [Line Items]
PSA Rate in Prior Years (decrease) \| $ / kWh		(0.002897)
Alternative to AZ Sun Program, Phase 1 \| ARIZONA PUBLIC SERVICE COMPANY \| Arizona Renewable Energy Standard and Tariff 2014
Regulatory Matters [Line Items]
Rate matter additional capacity from AZ Sun projects \| MW																						8
Solar Partner Program Phase 2 \| ARIZONA PUBLIC SERVICE COMPANY \| Arizona Renewable Energy Standard and Tariff 2014
Regulatory Matters [Line Items]
Rate matter additional capacity from AZ Sun projects \| MW																						2
Solar storage system, capacity (in MW) \| MW																						2
Number of energy storage systems \| storage_system																						2
Number of high solar penetration feeders \| penetration_feeder																						2
Solar Communities \| ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Arizona Renewable Energy Standard and Tariff 2018
Regulatory Matters [Line Items]
Program term											3 years
Minimum \| Solar Communities \| ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Arizona Renewable Energy Standard and Tariff 2018
Regulatory Matters [Line Items]
Required annual capital investment											$ 10,000,000
Maximum \| Solar Communities \| ARIZONA PUBLIC SERVICE COMPANY \| ACC \| Arizona Renewable Energy Standard and Tariff 2018
Regulatory Matters [Line Items]
Required annual capital investment											$ 15,000,000

Regulatory Matters - Deferred Fuel and Purchased Power Regulatory Asset (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Change in regulatory asset
Deferred fuel and purchased power	$ 78,277	$ 48,405	$ 60,303
Deferred fuel and purchased power amortization	(116,750)	14,767	(38,152)
ARIZONA PUBLIC SERVICE COMPANY
Change in regulatory asset
Deferred fuel and purchased power	78,277	48,405	60,303
Deferred fuel and purchased power amortization	(116,750)	14,767	(38,152)
ACC \| ARIZONA PUBLIC SERVICE COMPANY \| Power Supply Adjustor (PSA)
Change in regulatory asset
Beginning balance	75,637	12,465
Deferred fuel and purchased power	78,277	48,405
Deferred fuel and purchased power amortization	(116,750)	14,767
Ending balance	$ 37,164	$ 75,637	$ 12,465

Regulatory Matters - Four Corners, Cholla and Navajo Plant (Details) - ARIZONA PUBLIC SERVICE COMPANY - USD ($) $ in Millions			1 Months Ended		3 Months Ended	12 Months Ended
	Dec. 23, 2014	Dec. 30, 2013	Sep. 30, 2018	Apr. 30, 2018	Jun. 30, 2016	Dec. 31, 2018	Dec. 31, 2015
Retired power plant costs
Acquisition
Regulatory asset, net book value						$ 89.0
Navajo Plant
Acquisition
Regulatory asset, net book value						88.0
SCE \| Four Corners
Acquisition
Regulatory assets							$ 12.0
Regulatory assets, write of amount					$ 12.0
Four Corners Units 4 and 5 \| SCE
Acquisition
Ownership interest acquired (as a percent)		48.00%
Settlement agreement, ACC approved rate adjustment, annualized customer impact	$ 57.1		$ 58.5	$ 67.5
Transmission termination agreement net receipt due to negotiation of alternate arrangement		$ 40.0
Four Corners Units 4 and 5 \| SCE \| Four Corners cost deferral
Acquisition
Regulatory assets						$ 48.0
Amortization period						10 years

Regulatory Matters - Schedule of Regulatory Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Detail of regulatory assets
Regulatory assets, current	$ 166,902	$ 248,088
Regulatory assets, non-current	1,342,941	1,202,302
Pension
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	733,351	576,188
Retired power plant costs
Detail of regulatory assets
Regulatory assets, current	28,182	27,402
Regulatory assets, non-current	167,164	188,843
Income taxes - AFUDC equity
Detail of regulatory assets
Regulatory assets, current	6,457	3,828
Regulatory assets, non-current	151,467	142,852
Deferred fuel and purchased power - mark-to-market
Detail of regulatory assets
Regulatory assets, current	31,728	52,100
Regulatory assets, non-current	23,768	34,845
Deferred fuel and purchased power
Detail of regulatory assets
Regulatory assets, current	37,164	75,637
Regulatory assets, non-current	0	0
Four Corners cost deferral
Detail of regulatory assets
Regulatory assets, current	8,077	8,077
Regulatory assets, non-current	40,228	48,305
Income taxes — investment tax credit basis adjustment
Detail of regulatory assets
Regulatory assets, current	1,079	1,066
Regulatory assets, non-current	25,522	26,218
Lost fixed cost recovery
Detail of regulatory assets
Regulatory assets, current	32,435	59,844
Regulatory assets, non-current	0	0
Palo Verde VIE
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	20,015	19,395
Deferred compensation
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	36,523	36,413
Deferred property taxes
Detail of regulatory assets
Regulatory assets, current	8,569	8,569
Regulatory assets, non-current	66,356	74,926
Loss on reacquired debt
Detail of regulatory assets
Regulatory assets, current	1,637	1,637
Regulatory assets, non-current	13,668	15,305
Tax expense of Medicare subsidy
Detail of regulatory assets
Regulatory assets, current	1,235	1,236
Regulatory assets, non-current	6,176	7,415
TCA balancing account
Detail of regulatory assets
Regulatory assets, current	3,860	1,220
Regulatory assets, non-current	772	0
AG-1 deferral
Detail of regulatory assets
Regulatory assets, current	2,654	2,654
Regulatory assets, non-current	5,819	8,472
Mead-Phoenix transmission line CIAC
Detail of regulatory assets
Regulatory assets, current	332	332
Regulatory assets, non-current	10,044	10,376
Coal reclamation
Detail of regulatory assets
Regulatory assets, current	1,546	1,068
Regulatory assets, non-current	15,607	12,396
SCR deferral
Detail of regulatory assets
Regulatory assets, current	0	0
Regulatory assets, non-current	23,276	353
Other
Detail of regulatory assets
Regulatory assets, current	1,947	3,418
Regulatory assets, non-current	$ 3,185	$ 0

Regulatory Matters - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Detail of regulatory liabilities
Regulatory liabilities, current	$ 165,876	$ 100,086
Regulatory liabilities, non-current	2,325,976	2,452,536
Asset retirement obligations
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	278,585	332,171
Removal costs
Detail of regulatory liabilities
Regulatory liabilities, current	39,866	18,238
Regulatory liabilities, non-current	177,533	209,191
Other post retirement benefits
Detail of regulatory liabilities
Regulatory liabilities, current	37,864	37,642
Regulatory liabilities, non-current	125,903	151,985
Income taxes - deferred investment tax credit
Detail of regulatory liabilities
Regulatory liabilities, current	2,164	2,164
Regulatory liabilities, non-current	51,120	52,497
Income taxes - change in rates
Detail of regulatory liabilities
Regulatory liabilities, current	2,769	2,573
Regulatory liabilities, non-current	70,069	70,537
Spent nuclear fuel
Detail of regulatory liabilities
Regulatory liabilities, current	6,503	6,924
Regulatory liabilities, non-current	57,002	62,132
Renewable energy program
Detail of regulatory liabilities
Regulatory liabilities, current	44,966	23,155
Regulatory liabilities, non-current	20	0
Demand side management
Detail of regulatory liabilities
Regulatory liabilities, current	14,604	3,066
Regulatory liabilities, non-current	4,123	4,921
Sundance maintenance
Detail of regulatory liabilities
Regulatory liabilities, current	1,278	0
Regulatory liabilities, non-current	17,228	16,897
Deferred gains on utility property
Detail of regulatory liabilities
Regulatory liabilities, current	4,423	4,423
Regulatory liabilities, non-current	6,581	10,988
Four Corners coal reclamation
Detail of regulatory liabilities
Regulatory liabilities, current	1,858	1,858
Regulatory liabilities, non-current	17,871	18,921
Tax expense adjustor mechanism
Detail of regulatory liabilities
Regulatory liabilities, current	3,237	0
Regulatory liabilities, non-current	0	0
Other
Detail of regulatory liabilities
Regulatory liabilities, current	42	43
Regulatory liabilities, non-current	3,541	2,022
ACC \| Excess deferred income taxes - ACC - Tax Cuts and Jobs Act
Detail of regulatory liabilities
Regulatory liabilities, current	0	0
Regulatory liabilities, non-current	1,272,709	1,266,104
FERC \| Excess deferred income taxes - ACC - Tax Cuts and Jobs Act
Detail of regulatory liabilities
Regulatory liabilities, current	6,302	0
Regulatory liabilities, non-current	$ 243,691	$ 254,170

Income Taxes (Details) - USD ($)	3 Months Ended	12 Months Ended
Income Taxes (Details) - USD ($)	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Income Taxes
Reduction in net deferred income tax liabilities	$ 11,000,000		$ 1,140,000,000
Regulatory liabilities, non-current		$ 2,325,976,000	2,452,536,000
Interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS (less than)		1,000,000
General business tax credit carryforwards		14,000,000
increase (decrease) in deferred income taxes due to regulation adoption		19,000,000
ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Reduction in net deferred income tax liabilities			1,140,000,000
Regulatory liabilities, non-current		2,325,976,000	2,452,536,000
Gross-up for revenue requirement of rate regulation			377,000,000
Palo Verde VIE
Income Taxes
Income tax expense benefit attributable to non controlling interests		0
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act \| ARIZONA PUBLIC SERVICE COMPANY
Income Taxes
Regulatory liabilities, non-current	$ 9,000,000		$ 1,520,000,000
State
Income Taxes
Amount of state loss carryforwards		$ 7,000,000

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
Total unrecognized tax benefits, beginning of the year	$ 41,966	$ 36,075	$ 34,447
Additions for tax positions of the current year	3,436	2,937	2,695
Additions for tax positions of prior years	2,696	4,783	886
Reductions for tax positions of prior years for:
Changes in judgment	(1,764)	(1,829)	(1,953)
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	(5,603)	0	0
Total unrecognized tax benefits, end of the year	40,731	41,966	36,075
ARIZONA PUBLIC SERVICE COMPANY
Tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year
Total unrecognized tax benefits, beginning of the year	41,966	36,075	34,447
Additions for tax positions of the current year	3,436	2,937	2,695
Additions for tax positions of prior years	2,696	4,783	886
Reductions for tax positions of prior years for:
Changes in judgment	(1,764)	(1,829)	(1,953)
Settlements with taxing authorities	0	0	0
Lapses of applicable statute of limitations	(5,603)	0	0
Total unrecognized tax benefits, end of the year	$ 40,731	$ 41,966	$ 36,075

Income Taxes - Summary of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax [Line Items]
Tax positions, that if recognized, would decrease our effective tax rate	$ 19,504	$ 16,373	$ 11,313
Unrecognized tax benefit interest expense/(benefit) recognized	(780)	577	529
Unrecognized tax benefit interest accrued	1,130	1,910	1,333
ARIZONA PUBLIC SERVICE COMPANY
Income Tax [Line Items]
Tax positions, that if recognized, would decrease our effective tax rate	19,504	16,373	11,313
Unrecognized tax benefit interest expense/(benefit) recognized	(780)	577	529
Unrecognized tax benefit interest accrued	$ 1,130	$ 1,910	$ 1,333

Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current:
Federal									$ 18,375	$ 11,624	$ 8,630
State									3,342	3,052	1,259
Total current									21,717	14,676	9,889
Deferred:
Federal									94,721	223,729	201,743
State									17,464	19,867	24,779
Total deferred									112,185	243,596	226,522
Income tax expense	$ 6,795	$ 84,333	$ 44,039	$ (1,265)	$ 20,775	$ 144,319	$ 88,967	$ 4,211	133,902	258,272	236,411
ARIZONA PUBLIC SERVICE COMPANY
Current:
Federal									88,180	21,512	711
State									1,877	2,778	4,276
Total current									90,057	24,290	4,987
Deferred:
Federal									32,436	221,078	215,178
State									22,321	23,800	25,677
Total deferred									54,757	244,878	240,855
Income tax expense									$ 144,814	$ 269,168	$ 245,842

Income Taxes - Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
Federal income tax expense at statutory rate									$ 139,533	$ 268,177	$ 244,278
State income tax net of federal income tax benefit									16,411	14,897	16,311
Nondeductible expenditures associated with ballot initiative									7,879	0	0
Stock compensation									(1,804)	(6,659)	(2,951)
Excess deferred income taxes - Tax Cuts and Jobs Act									(6,725)	9,348	0
Allowance for equity funds used during construction (see Note 1)									(7,231)	(12,937)	(11,724)
Palo Verde VIE noncontrolling interest (see Note 18)									(4,094)	(6,823)	(6,823)
Investment tax credit amortization									(6,742)	(6,715)	(5,887)
Other									(3,325)	(1,016)	3,207
Income tax expense	$ 6,795	$ 84,333	$ 44,039	$ (1,265)	$ 20,775	$ 144,319	$ 88,967	$ 4,211	133,902	258,272	236,411
ARIZONA PUBLIC SERVICE COMPANY
Income Tax Reconciliation Increases Reductions in Tax Expense [Abstract]
Federal income tax expense at statutory rate									154,260	277,540	254,617
State income tax net of federal income tax benefit									19,091	17,276	18,750
Nondeductible expenditures associated with ballot initiative									0	0	0
Stock compensation									(780)	(3,489)	(1,937)
Excess deferred income taxes - Tax Cuts and Jobs Act									(4,715)	9,431	0
Allowance for equity funds used during construction (see Note 1)									(7,231)	(12,937)	(11,724)
Palo Verde VIE noncontrolling interest (see Note 18)									(4,094)	(6,823)	(6,823)
Investment tax credit amortization									(6,742)	(6,715)	(5,887)
Other									(4,975)	(5,115)	(1,154)
Income tax expense									$ 144,814	$ 269,168	$ 245,842

Income Taxes - Components of Deferred Income Tax Liability (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
DEFERRED TAX ASSETS
Risk management activities	$ 15,785	$ 25,103
Regulatory liabilities:
Excess deferred income taxes - Tax Cuts and Jobs Act	376,869	376,906
Asset retirement obligation and removal costs	117,201	135,847
Unamortized investment tax credits	53,284	54,661
Other postretirement liabilities	40,532	47,021
Other	40,380	37,489
Pension liabilities	112,019	83,126
Coal reclamation liabilities	47,508	45,802
Renewable energy incentives	30,779	33,546
Credit and loss carryforwards	1,755	53,946
Other	58,820	56,630
Total deferred tax assets	894,932	950,077
DEFERRED TAX LIABILITIES
Plant-related	(2,277,724)	(2,220,886)
Risk management activities	(237)	(491)
Other postretirement assets and other special use funds	(57,697)	(66,134)
Regulatory assets:
Allowance for equity funds used during construction	(39,086)	(36,365)
Deferred fuel and purchased power	(23,086)	(40,778)
Pension benefits	(181,504)	(142,848)
Retired power plant costs (see Note 3)	(48,348)	(53,611)
Other	(72,096)	(74,423)
Other	(2,575)	(5,346)
Total deferred tax liabilities	(2,702,353)	(2,640,882)
Deferred income taxes — net	(1,807,421)	(1,690,805)
ARIZONA PUBLIC SERVICE COMPANY
DEFERRED TAX ASSETS
Risk management activities	15,785	25,103
Regulatory liabilities:
Excess deferred income taxes - Tax Cuts and Jobs Act	376,869	376,906
Asset retirement obligation and removal costs	117,201	135,847
Unamortized investment tax credits	53,284	54,661
Other postretirement liabilities	40,532	47,021
Other	40,380	37,489
Pension liabilities	107,009	77,280
Coal reclamation liabilities	47,508	45,802
Renewable energy incentives	30,779	33,546
Credit and loss carryforwards	0	1,920
Other	59,919	62,421
Total deferred tax assets	889,266	897,996
DEFERRED TAX LIABILITIES
Plant-related	(2,277,724)	(2,220,886)
Risk management activities	(237)	(491)
Other postretirement assets and other special use funds	(57,274)	(65,733)
Regulatory assets:
Allowance for equity funds used during construction	(39,086)	(36,365)
Deferred fuel and purchased power	(23,086)	(40,778)
Pension benefits	(181,504)	(142,848)
Retired power plant costs (see Note 3)	(48,348)	(53,611)
Other	(72,096)	(74,423)
Other	(2,575)	(5,346)
Total deferred tax liabilities	(2,701,930)	(2,640,481)
Deferred income taxes — net	$ (1,812,664)	$ (1,742,485)

Lines of Credit and Short-Term Borrowings - Schedule of Credit Facilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pinnacle West
Lines of Credit and Short-Term Borrowings
Commitment fees (as a percent)	0.125%	0.125%
ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Commitment fees (as a percent)	0.10%	0.10%
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Commitments under Credit Facilities	$ 1,350,000	$ 1,325,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(76,400)	(95,400)
Amount of Credit Facilities Available	1,273,600	1,229,600
Revolving credit facility \| Pinnacle West
Lines of Credit and Short-Term Borrowings
Commitments under Credit Facilities	350,000	325,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	(76,400)	(95,400)
Amount of Credit Facilities Available	273,600	229,600
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Commitments under Credit Facilities	1,000,000	1,000,000
Outstanding Commercial Paper and Revolving Credit Facility Borrowings	0	0
Amount of Credit Facilities Available	$ 1,000,000	$ 1,000,000

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References + Details

Lines of Credit and Short-Term Borrowings (Details)	Jun. 28, 2018 USD ($)	Jun. 27, 2018 USD ($)	Dec. 31, 2018 USD ($) Facility	Nov. 27, 2018 USD ($)	Jul. 12, 2018 USD ($)	Jul. 11, 2018 USD ($)	Dec. 31, 2017 USD ($)
Lines of Credit and Short-Term Borrowings
Short-term borrowings			$ 76,400,000				$ 95,400,000
Pinnacle West
Lines of Credit and Short-Term Borrowings
Short-term borrowings			76,400,000				95,400,000
ARIZONA PUBLIC SERVICE COMPANY \| ACC
Debt Provisions
Percentage of APS's capitalization used in calculation of short-term debt authorization				7.00%
Required amount to be used in purchases of natural gas and power which is used in calculation of short-term debt authorization				$ 500,000,000
Revolving credit facility
Lines of Credit and Short-Term Borrowings
Amount committed			1,350,000,000				1,325,000,000
Long-term line of credit			76,400,000				95,400,000
Revolving credit facility \| Pinnacle West
Lines of Credit and Short-Term Borrowings
Amount committed			350,000,000				325,000,000
Long-term line of credit			76,400,000				95,400,000
Revolving credit facility \| Pinnacle West \| Revolving credit facility maturing July 2018
Lines of Credit and Short-Term Borrowings
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders		$ 125,000,000
Debt instrument, term		364 days
Revolving credit facility \| Pinnacle West \| Revolving Credit Facility Maturing June 2019 [Member]
Lines of Credit and Short-Term Borrowings
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders	$ 150,000,000
Debt instrument, term	364 days
Short-term borrowings			54,000,000
Revolving credit facility \| Pinnacle West \| Revolving credit facility maturing May 2021
Lines of Credit and Short-Term Borrowings
Amount committed						$ 200,000,000
Revolving credit facility \| Pinnacle West \| Revolving credit facility maturing July 2023
Lines of Credit and Short-Term Borrowings
Amount committed					$ 200,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders			300,000,000
Long-term line of credit			0
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Amount committed			1,000,000,000				1,000,000,000
Long-term line of credit			0				$ 0
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing June 2022
Lines of Credit and Short-Term Borrowings
Amount committed			500,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing May 2021
Lines of Credit and Short-Term Borrowings
Amount committed						$ 500,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility maturing July 2023
Lines of Credit and Short-Term Borrowings
Amount committed			500,000,000		$ 500,000,000
Revolving credit facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving Credit Facility Maturing in 2022 and 2023 [Member]
Lines of Credit and Short-Term Borrowings
Amount committed			1,000,000,000
Additional capacity increase available			700,000,000
Maximum borrowing capacity on credit facility upon satisfaction of certain conditions and consent of lenders			1,400,000,000
Long-term line of credit			$ 0
Number of credit facilities \| Facility			2
Letter of credit \| Pinnacle West \| Revolving credit facility maturing July 2023
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit			$ 0
Letter of credit \| ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Outstanding letters of credit			200,000
Commercial paper \| Pinnacle West \| Revolving credit facility maturing July 2023
Lines of Credit and Short-Term Borrowings
Commercial paper			22,000,000
Commercial paper \| ARIZONA PUBLIC SERVICE COMPANY
Lines of Credit and Short-Term Borrowings
Maximum commercial paper support available under credit facility			500,000,000
Commercial paper \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving Credit Facility Maturing in 2022 and 2023 [Member]
Lines of Credit and Short-Term Borrowings
Long-term line of credit			$ 0
LIBOR \| Revolving credit facility \| Pinnacle West \| Revolving Credit Facility Maturing June 2019 [Member]
Lines of Credit and Short-Term Borrowings
Debt instrument, basis spread on variable rate		0.70%

Long-Term Debt and Liquidity Matters (Details) - USD ($)					12 Months Ended
	Dec. 21, 2018	Nov. 30, 2018	Jun. 26, 2018	May 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Nov. 27, 2018	Nov. 26, 2018	Aug. 09, 2018
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)					3.90%
Maximum
Debt Provisions
Ratio of consolidated debt to consolidated capitalization (as a percent)					65.00%
Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Contribution to subsidiaries	$ 150,000,000				$ 142,796,000	$ 178,027,000	$ 19,242,000
Debt Provisions
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)					50.00%
Pinnacle West \| Term loan
Long-Term Debt and Liquidity Matters [Line Items]
Maximum borrowing capacity on credit facility	$ 150,000,000
ARIZONA PUBLIC SERVICE COMPANY
Debt Provisions
Actual ratio of consolidated debt to total consolidated capitalization required to be maintained as per the debt covenant (as a percent)					46.00%
ARIZONA PUBLIC SERVICE COMPANY \| ACC
Debt Provisions
Long term debt authorization								$ 5,900,000,000	$ 5,100,000,000
ARIZONA PUBLIC SERVICE COMPANY \| Senior notes
Long-Term Debt and Liquidity Matters [Line Items]
Notes issued										$ 300,000,000
Interest rate (as a percent)										4.20%
Total Pollution Control Bonds \| ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Extinguishment of debt				$ 32,000,000
Senior unsecured notes \| Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)					2.25%
Term loan facility \| ARIZONA PUBLIC SERVICE COMPANY \| Revolving credit facility
Long-Term Debt and Liquidity Matters [Line Items]
Extinguishment of debt		$ 100,000,000	$ 50,000,000

Long-Term Debt and Liquidity Matters - Components of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Long-Term Debt and Liquidity Matters [Line Items]
Total long-term debt	$ 5,138,232	$ 4,871,713
Long-term debt less current maturities (Note 6)	$ 4,638,232	4,789,713
Interest rate (as a percent)	3.90%
Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 5,176,125
Unamortized discount	(121)	(184)
Unamortized debt issue costs	(1,083)	(1,395)
Total long-term debt	448,796	298,421
Less current maturities	0	0
Total long-term debt less current maturities	448,796	298,421
Long-term debt less current maturities (Note 6)	448,796	298,421
ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	4,726,125
Unamortized discount	(12,638)	(11,288)
Unamortized premium	7,736	8,049
Unamortized debt issue costs	(31,787)	(31,594)
Total long-term debt	4,689,436	4,573,292
Less current maturities	500,000	82,000
Total long-term debt less current maturities	4,189,436	4,491,292
Pollution Control Bonds - Variable \| ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 35,975	$ 35,975
Pollution Control Bonds - Variable \| ARIZONA PUBLIC SERVICE COMPANY \| Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)	1.76%	1.77%
Pollution Control Bonds - Fixed \| ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 115,150	$ 147,150
Pollution Control Bonds - Fixed \| ARIZONA PUBLIC SERVICE COMPANY \| Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	4.70%
Total Pollution Control Bonds \| ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 151,125	183,125
Senior unsecured notes \| ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 4,575,000	4,275,000
Senior unsecured notes \| ARIZONA PUBLIC SERVICE COMPANY \| Minimum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	2.20%
Senior unsecured notes \| ARIZONA PUBLIC SERVICE COMPANY \| Maximum
Long-Term Debt and Liquidity Matters [Line Items]
Interest rate (as a percent)	8.75%
Senior unsecured notes \| Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Gross long-term debt	$ 300,000	$ 300,000
Interest rate (as a percent)	2.25%
Term loan \| ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Weighted-average interest rate (as a percent)		2.24%
Term loan \| Term loans \| ARIZONA PUBLIC SERVICE COMPANY
Long-Term Debt and Liquidity Matters [Line Items]
Term loans	$ 0	$ 150,000
Term loan \| Term Loan Facility Maturing 2020 \| Pinnacle West
Long-Term Debt and Liquidity Matters [Line Items]
Term loans	$ 150,000	$ 0
Weighted-average interest rate (as a percent)	3.02%

Long-Term Debt and Liquidity Matters - Future Principal Payments (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Pinnacle West
Principal payments due on long-term debt
2019	$ 500,000
2020	700,000
2021	0
2022	0
2023	0
Thereafter	3,976,125
Total	5,176,125
ARIZONA PUBLIC SERVICE COMPANY
Principal payments due on long-term debt
2019	500,000
2020	250,000
2021	0
2022	0
2023	0
Thereafter	3,976,125
Total	$ 4,726,125

Long-Term Debt and Liquidity Matters - Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Estimated fair value of long-term debt, including current maturities
Carrying Amount	$ 5,138,232	$ 4,871,713
Fair Value	5,233,563	5,304,956
Pinnacle West
Estimated fair value of long-term debt, including current maturities
Carrying Amount	448,796	298,421
Fair Value	443,955	298,608
ARIZONA PUBLIC SERVICE COMPANY
Estimated fair value of long-term debt, including current maturities
Carrying Amount	4,689,436	4,573,292
Fair Value	$ 4,789,608	$ 5,006,348

Retirement Plans and Other Benefits Retirement Plans and Other Benefits - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Plan Design Changes [Abstract]
Amount of other postretirement benefit trust assets for union employee medical costs	$ 186,000,000
Partnership funding commitments, contribution amount (up to)	75,000,000
Partnership funding commitments, funded amount	$ 62,000,000
Pension Benefits
Plan Design Changes [Abstract]
Expected long-term return on plan assets for next fiscal year (as a percent)	6.25%
Contributions
Employer contributions	$ 50,000,000	$ 100,000,000	$ 100,000,000
Minimum contributions under MAP-21
Minimum contributions under MAP-21	0
Voluntary employer contributions over next three years (up to)	$ 350,000,000
Other Benefits
Plan Design Changes [Abstract]
Expected long-term return on plan assets for next fiscal year (as a percent)	5.55%
Contributions
Employer contributions	$ 0	353,000
Employee savings plan benefits
Retiree medical cost reimbursement	72,000,000
Pinnacle West
Employee savings plan benefits
Expenses recorded for the defined contribution savings plan	$ 11,000,000	10,000,000	10,000,000
ARIZONA PUBLIC SERVICE COMPANY
Employee savings plan benefits
APS's employees share of total cost of the plans (as a percent)	99.00%
ARIZONA PUBLIC SERVICE COMPANY \| Other Benefits
Contributions
Employer contributions	$ 0	$ 1,000,000	$ 1,000,000

Retirement Plans and Other Benefits - Net Periodic Benefit Costs and Portion including Portion Charged to Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net periodic benefit costs and the portion of these costs charged to expense
Portion of cost charged to expense	$ (49,791)	$ (24,664)	$ (20,373)
Pension Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost-benefits earned during the period	56,669	54,858	53,792
Interest cost on benefit obligation	124,689	129,756	131,647
Expected return on plan assets	(182,853)	(174,271)	(173,906)
Amortization of prior service cost (credit)	0	81	527
Amortization of net actuarial loss	32,082	47,900	40,717
Net periodic benefit cost (benefit)	30,587	58,324	52,777
Portion of cost charged to expense	10,120	27,295	26,172
Other Benefits
Net periodic benefit costs and the portion of these costs charged to expense
Service cost-benefits earned during the period	21,100	17,119	14,993
Interest cost on benefit obligation	28,147	29,959	29,721
Expected return on plan assets	(42,082)	(53,401)	(36,495)
Amortization of prior service cost (credit)	(37,842)	(37,842)	(37,883)
Amortization of net actuarial loss	0	5,118	4,589
Net periodic benefit cost (benefit)	(30,677)	(39,047)	(25,075)
Portion of cost charged to expense	$ (21,426)	$ (18,274)	$ (12,435)

Retirement Plans and Other Benefits - Changes Benefit Obligations and Funded Status (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	$ 3,394,186	$ 3,204,462
Service cost	56,669	54,858	$ 53,792
Interest cost	124,689	129,756	131,647
Benefit payments	(184,161)	(166,342)
Actuarial (gain) loss	(200,757)	171,452
Benefit obligation at the end of the period	3,190,626	3,394,186	3,204,462
Change in Plan Assets
Balance at the beginning of the period	3,057,027	2,675,357
Actual return on plan assets	(201,078)	428,374
Employer contributions	50,000	100,000	100,000
Benefit payments	(172,473)	(146,704)
Transfer to active union medical account	0	0
Balance at the end of the period	2,733,476	3,057,027	2,675,357
Funded Status at the end of the period	(457,150)	(337,159)
Other Benefits
Change in Benefit Obligation
Benefit obligation at the beginning of the period	753,393	716,445
Service cost	21,100	17,119	14,993
Interest cost	28,147	29,959	29,721
Benefit payments	(31,540)	(30,144)
Actuarial (gain) loss	(94,329)	20,014
Benefit obligation at the end of the period	676,771	753,393	716,445
Change in Plan Assets
Balance at the beginning of the period	1,022,371	882,651
Actual return on plan assets	(40,354)	139,367
Employer contributions	0	353
Benefit payments	(72,453)	0
Transfer to active union medical account	(185,887)	0
Balance at the end of the period	723,677	1,022,371	$ 882,651
Funded Status at the end of the period	$ 46,906	$ 268,978

Retirement Plans and Other Benefits - Projected Benefit Obligation for Pension Plans (Details) - Pension Benefits - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Projected benefit obligation and the accumulated benefit obligation for pension plans with an accumulated obligation in excess of plan assets
Projected benefit obligation	$ 3,190,626	$ 3,394,186
Accumulated benefit obligation	3,038,774	3,227,233
Fair value of plan assets	$ 2,733,476	$ 3,057,027

Retirement Plans and Other Benefits - Amounts Recognized on the Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	$ 46,906	$ 268,978
Pension Benefits
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	0	0
Current liability	(13,980)	(9,859)
Noncurrent liability	(443,170)	(327,300)
Net amount recognized	(457,150)	(337,159)
Other Benefits
Amounts recognized on the Consolidated Balance Sheets
Noncurrent asset	46,906	268,978
Current liability	0	0
Noncurrent liability	0	0
Net amount recognized	$ 46,906	$ 268,978

Retirement Plans and Other Benefits - Impact to Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Pension Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	$ 794,292	$ 643,199
Prior service credit	0	0
APS’s portion recorded as a regulatory (asset) liability	(733,351)	(576,188)
Income tax expense (benefit)	(15,083)	(24,915)
Accumulated other comprehensive loss	45,858	42,096
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	43,248
Prior service credit	0
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2019	43,248
Other Benefits
Details related to accumulated other comprehensive loss
Net actuarial loss	63,544	75,439
Prior service credit	(227,733)	(265,575)
APS’s portion recorded as a regulatory (asset) liability	163,767	189,627
Income tax expense (benefit)	561	853
Accumulated other comprehensive loss	139	$ 344
Estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2014
Net actuarial loss	0
Prior service credit	(37,821)
Total amounts estimated to be amortized from accumulated other comprehensive loss (gain) and regulatory assets (liabilities) in 2019	$ (37,821)

Retirement Plans and Other Benefits - Weighted-Average Assumptions for Pensions and Other Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Weighted-average assumptions used to determine benefit obligations
Rate of compensation increase (as a percent)	4.00%	4.00%
Initial pre-65 healthcare cost trend rate (as a percent)	7.00%	7.00%
Initial post-65 healthcare cost trend rate (as a percent)	4.75%	4.75%
Ultimate health care cost trend rate (as a percent)	4.75%	4.75%
Number of years to ultimate trend rate (pre-65 participants)	7 years	8 years
Weighted-average assumptions used to determine net periodic benefit costs
Initial pre-65 health care cost trend rate (as a percent)	7.00%	7.00%	7.00%
Initial post-65 health care cost trend rate (as a percent)	4.75%	5.00%	5.00%
Ultimate healthcare cost trend rate (as a percent)	4.75%	5.00%	5.00%
Number of years to ultimate trend rate (pre-65 participants)	8 years	4 years	4 years
Pension Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	4.34%	3.65%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	3.65%	4.08%	4.37%
Rate of compensation increase (as a percent)	4.00%	4.00%	4.00%
Expected long-term return on plan assets (as a percent)	6.05%	6.55%	6.90%
Other Benefits
Weighted-average assumptions used to determine benefit obligations
Discount rate (as a percent)	4.39%	3.71%
Weighted-average assumptions used to determine net periodic benefit costs
Discount rate (as a percent)	3.71%	4.17%	4.52%
Expected long-term return on plan assets (as a percent)	5.40%	6.05%	4.45%
Effects of one percentage point change in the assumed initial and ultimate health care cost trend rates
Effect of 1% increase on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$ 10,235
Effect of 1% decrease on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	(4,322)
Effect of 1% increase on service and interest cost components of net periodic other postretirement benefit costs	11,223
Effect of 1% decrease on service and interest cost components of net periodic other postretirement benefit costs	(8,479)
Effect of 1% increase on the accumulated other postretirement benefit obligation	101,224
Effect of 1% decrease on the accumulated other postretirement benefit obligation	$ (81,144)

Retirement Plans and Other Benefits - Asset Allocation (Details)	Dec. 31, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	100.00%
Actual Allocation	100.00%
Pension Benefits \| Long-term fixed income assets
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	62.00%
Actual Allocation	64.00%
Pension Benefits \| Return-generating assets
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	38.00%
Target Allocation	38.00%
Actual Allocation	36.00%
Pension Benefits \| Equities in US and other developed markets
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	18.00%
Pension Benefits \| Equities in emerging markets
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	6.00%
Pension Benefits \| Alternative investments
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	14.00%
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	100.00%
Other Benefits \| Long-term fixed income assets
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	69.00%
Other Benefits \| Return-generating assets
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	31.00%

Retirement Plans and Other Benefits - Fair Value of Pinnacle West's Pension Plan (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	$ 726,093	$ 903,085
Fair value of plan assets	2,733,476	3,057,027	$ 2,675,357
Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	690,737	686,941
Pension Benefits \| Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	1,316,646	1,467,001
Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	90,955	99,910
Fair value of plan assets	723,677	1,022,371	$ 882,651
Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	461,905	583,796
Other Benefits \| Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	170,817	338,665
Corporate \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	1,237,744	1,365,194
Corporate \| Pension Benefits \| Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	1,237,744	1,365,194
Corporate \| Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	163,286	306,008
Corporate \| Other Benefits \| Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	163,286	306,008
U.S. Treasury \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	372,649	221,291
U.S. Treasury \| Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	372,649	221,291
U.S. Treasury \| Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	318,017	336,963
U.S. Treasury \| Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	318,017	336,963
Other \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	78,902	100,599
Other \| Pension Benefits \| Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	78,902	100,599
Other \| Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	7,531	32,508
Other \| Other Benefits \| Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	7,531	32,508
Common stock equities \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	196,661	228,088
Common stock equities \| Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	196,661	228,088
Common stock equities \| Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	129,199	196,153
Common stock equities \| Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	129,199	196,153
Mutual funds \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	120,976	233,732
Mutual funds \| Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	120,976	233,732
Mutual funds \| Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	10,963	39,269
Mutual funds \| Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	10,963	39,269
Equities \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	272,926	408,763
Fair value of plan assets	272,926	408,763
Equities \| Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	65,720	75,310
Fair value of plan assets	65,720	75,310
Real estate \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	165,123	171,569
Fair value of plan assets	165,123	171,569
Real estate \| Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	19,054	15,422
Fair value of plan assets	19,054	15,422
Fixed income securities \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	86,483	90,869
Fair value of plan assets	86,483	90,869
Partnerships \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	125,217	133,379
Fair value of plan assets	125,217	133,379
Short-term investments and other \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	76,344	98,505
Fair value of plan assets	76,344	99,713
Short-term investments and other \| Pension Benefits \| Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	0	1,208
Short-term investments and other \| Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Other	6,181	9,178
Fair value of plan assets	9,814	20,595
Short-term investments and other \| Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	3,633
Other		11,268
Short-term investments and other \| Other Benefits \| Significant Other Observable Inputs (Level 2)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	0
Other		149
Defined Benefit Plan, Cash and Cash Equivalents [Member] \| Pension Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	451	3,830
Defined Benefit Plan, Cash and Cash Equivalents [Member] \| Pension Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	451	3,830
Defined Benefit Plan, Cash and Cash Equivalents [Member] \| Other Benefits
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Fair value of plan assets	93	143
Defined Benefit Plan, Cash and Cash Equivalents [Member] \| Other Benefits \| Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair value of Pinnacle West's pension plan and other postretirement benefit plan assets, by asset category
Gross fair value of plan assets	$ 93	$ 143

Retirement Plans and Other Benefits - Estimated Future Benefit Payments (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Pension Benefits
Estimated Future Benefit Payments
2019	$ 188,492
2020	193,087
2021	198,471
2022	204,399
2023	211,346
Years 2024-2028	1,093,319
Other Benefits
Estimated Future Benefit Payments
2019	32,622
2020	34,199
2021	35,551
2022	36,673
2023	37,405
Years 2024-2028	$ 187,023

Leases (Details) $ in Thousands	12 Months Ended
Leases (Details) $ in Thousands	Dec. 31, 2018 USD ($) Trust	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 1986 Trust
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
Lease expense	$ 18,000	$ 18,000	$ 16,000
Future minimum payments due	54,000
Operating lease, cost	47,000	60,000	82,000
Contingent rents	109,000	100,000	88,000
Pinnacle West
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2019	13,747
2020	12,428
2021	9,478
2022	6,513
2023	5,359
Thereafter	42,236
Total future lease commitments	89,761
Palo Verde Lessor Trusts
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
Number of VIE lessor trusts \| Trust				3
ARIZONA PUBLIC SERVICE COMPANY
Estimated future minimum lease payments for operating leases, excluding purchased power agreements
2019	13,411
2020	12,143
2021	9,282
2022	6,321
2023	5,171
Thereafter	40,656
Total future lease commitments	86,984
Lease expense	$ 17,000	$ 17,000	$ 15,000
Number of VIE lessor trusts \| Trust	3			3

Jointly-Owned Facilities (Details) - ARIZONA PUBLIC SERVICE COMPANY $ in Thousands	Dec. 31, 2018 USD ($)
Navajo Plant
Interests in jointly-owned facilities
Ownership interest by noncontrolling owners (as a percent)	14.00%
Palo Verde Units 1 and 3
Interests in jointly-owned facilities
Percent Owned	29.10%
Plant in Service	$ 1,887,729
Accumulated Depreciation	1,095,878
Construction work in progress	$ 25,185
Palo Verde Unit 2
Interests in jointly-owned facilities
Percent Owned	16.80%
Plant in Service	$ 638,419
Accumulated Depreciation	369,372
Construction work in progress	$ 20,852
Palo Verde Common
Interests in jointly-owned facilities
Percent Owned	28.00%
Plant in Service	$ 752,300
Accumulated Depreciation	277,414
Construction work in progress	39,995
Palo Verde Sale Leaseback
Interests in jointly-owned facilities
Plant in Service	351,050
Accumulated Depreciation	245,275
Construction work in progress	$ 0
Four Corners Generating Station
Interests in jointly-owned facilities
Percent Owned	63.00%
Plant in Service	$ 1,466,579
Accumulated Depreciation	544,308
Construction work in progress	$ 23,430
Cholla Common Facilities
Interests in jointly-owned facilities
Percent Owned	50.50%
Plant in Service	$ 183,390
Accumulated Depreciation	82,434
Construction work in progress	$ 893
ANPP 500kV System
Interests in jointly-owned facilities
Percent Owned	33.50%
Plant in Service	$ 129,587
Accumulated Depreciation	49,340
Construction work in progress	$ 2,705
Navajo Southern System
Interests in jointly-owned facilities
Percent Owned	26.70%
Plant in Service	$ 82,046
Accumulated Depreciation	30,464
Construction work in progress	$ 284
Palo Verde — Yuma 500kV System
Interests in jointly-owned facilities
Percent Owned	19.00%
Plant in Service	$ 15,304
Accumulated Depreciation	6,729
Construction work in progress	$ 530
Four Corners Switchyards
Interests in jointly-owned facilities
Percent Owned	63.10%
Plant in Service	$ 68,707
Accumulated Depreciation	15,436
Construction work in progress	$ 1,334
Phoenix — Mead System
Interests in jointly-owned facilities
Percent Owned	17.10%
Plant in Service	$ 39,329
Accumulated Depreciation	18,527
Construction work in progress	$ 44
Palo Verde — Rudd 500kV System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 93,887
Accumulated Depreciation	25,573
Construction work in progress	$ 302
Morgan — Pinnacle Peak System
Interests in jointly-owned facilities
Percent Owned	64.60%
Plant in Service	$ 117,722
Accumulated Depreciation	16,744
Construction work in progress	$ 0
Round Valley System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 515
Accumulated Depreciation	153
Construction work in progress	$ 0
Palo Verde — Morgan System
Interests in jointly-owned facilities
Percent Owned	87.90%
Plant in Service	$ 219,292
Accumulated Depreciation	6,660
Construction work in progress	$ 0
Hassayampa — North Gila System
Interests in jointly-owned facilities
Percent Owned	80.00%
Plant in Service	$ 142,541
Accumulated Depreciation	9,805
Construction work in progress	$ 0
Cholla 500kV Switchyard
Interests in jointly-owned facilities
Percent Owned	85.70%
Plant in Service	$ 5,078
Accumulated Depreciation	1,414
Construction work in progress	$ 38
Saguaro 500kV Switchyard
Interests in jointly-owned facilities
Percent Owned	60.00%
Plant in Service	$ 20,414
Accumulated Depreciation	12,790
Construction work in progress	$ 0
Kyrene — Knox System
Interests in jointly-owned facilities
Percent Owned	50.00%
Plant in Service	$ 578
Accumulated Depreciation	307
Construction work in progress	$ 0

Commitments and Contingencies - Palo Verde Nuclear Generating Station and Contractual Obligations (Details)		12 Months Ended
	Aug. 18, 2014 USD ($)	Dec. 31, 2018 USD ($) Trust	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 1986 Trust
ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Maximum insurance against public liability per occurrence for a nuclear incident		$ 14,100,000,000
Maximum available nuclear liability insurance		450,000,000
Remaining nuclear liability insurance through mandatory industry wide retrospective assessment program		13,600,000,000
Maximum assessment per reactor for each nuclear incident		137,600,000
Annual limit per incident with respect to maximum assessment		$ 20,500,000
Number of VIE lessor trusts \| Trust		3			3
Maximum potential retrospective assessment per incident of APS		$ 120,100,000
Annual payment limitation with respect to maximum potential retrospective assessment		17,900,000
Amount of "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde		2,800,000,000
Maximum amount that APS could incur under the current NEIL policies for each retrospective assessment		24,800,000
Collateral assurance provided based on rating triggers		$ 71,200,000
Period to provide collateral assurance based on rating triggers		20 days
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2019		$ 622,000,000
2020		555,000,000
2021		558,000,000
2022		563,000,000
2023		560,000,000
Thereafter		5,900,000,000
ARIZONA PUBLIC SERVICE COMPANY \| Coal take-or-pay commitments
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2019		179,879,000
2020		181,059,000
2021		184,944,000
2022		186,244,000
2023		187,518,000
Thereafter		1,422,253,000
Total obligation		2,341,900,000
Present value of commitments		1,700,000,000
Total purchases		206,093,000	$ 165,220,000	$ 160,066,000
ARIZONA PUBLIC SERVICE COMPANY \| Renewable energy credits
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2019		37,000,000
2020		36,000,000
2021		34,000,000
2022		31,000,000
2023		30,000,000
Thereafter		155,000,000
ARIZONA PUBLIC SERVICE COMPANY \| Coal Mine Reclamation Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
2019		32,000,000
2020		21,000,000
2021		21,000,000
2022		22,000,000
2023		24,000,000
Thereafter		167,000,000
ARIZONA PUBLIC SERVICE COMPANY \| Coal Mine Reclamation Balance Sheet Obligations
Fuel and Purchased Power Commitments and Purchase Obligations [Abstract]
Total obligation		213,000,000	$ 216,000,000
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal
Palo Verde Nuclear Generating Station [Abstract]
Settlement amount, awarded to company	$ 57,400,000	10,200,000
Proceeds from legal settlements		74,200,000
Arizona Public Service Company and Palo Verde Owners vs. United States Department of Energy - Spent Nuclear Fuel and Waste Disposal \| ARIZONA PUBLIC SERVICE COMPANY
Palo Verde Nuclear Generating Station [Abstract]
Settlement amount, awarded to company	$ 16,700,000	3,000,000.0
Proceeds from legal settlements		$ 21,600,000

Commitments and Contingencies - Superfund-Related Matters and Southwest Power Outage (Details) - ARIZONA PUBLIC SERVICE COMPANY - Contaminated groundwater wells $ in Millions			12 Months Ended
	Dec. 16, 2016 plaintiff	Aug. 06, 2013 Defendant	Dec. 31, 2018 USD ($)
Superfund
Costs related to investigation and study under Superfund site \| $			$ 2
Number of defendants against whom Roosevelt Irrigation District ("RID") filed lawsuit \| Defendant		24
Number of plaintiffs \| plaintiff	2

Commitments and Contingencies - Environmental Matters and Financial Assurances (Details) $ in Millions					12 Months Ended
	Jul. 03, 2018 USD ($)	Jun. 29, 2018 USD ($)	Jun. 13, 2017 USD ($)	Jul. 06, 2016 guarantee	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Mar. 12, 2018 USD ($)
Payment Guarantee
Financial Assurances
Number of parental guarantees \| guarantee				5
Letter of credit \| ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit					$ 0.2
Equity Lessors Sale Leaseback Letter of Credit \| ARIZONA PUBLIC SERVICE COMPANY
Financial Assurances
Outstanding letters of credit					17.0
Four Corners \| NTEC
Environmental Matters [Abstract]
Option to purchase, ownership interest (as a percent)	7.00%			7.00%
Payment received for coal supply agreement	$ 70.0
Four Corners \| 4CA
Environmental Matters [Abstract]
Percentage share cost of control	7.00%			7.00%
Four Corners \| Coal Supply Agreement Arbitration
Environmental Matters [Abstract]
Damages sought			$ 30.0
Litigation settlement		$ 45.0
Four Corners \| Coal Supply Agreement Arbitration \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Damages sought			$ 17.0
Litigation settlement		$ 34.0
Prepaid energy related inventory, coal							$ 24.0
Four Corners \| Coal Supply Agreement Arbitration \| NTEC
Environmental Matters [Abstract]
Option to purchase, ownership interest (as a percent)				7.00%
Four Corners \| Coal Supply Agreement Arbitration \| 4CA
Environmental Matters [Abstract]
Payment received for coal supply agreement						$ 10.0
Operating and maintenance cost reimbursement receivable					10.0	$ 20.0
Regional Haze Rules \| Navajo Generating Station \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Expected environmental cost					$ 200.0
Regional Haze Rules \| Four Corners Units 4 and 5 \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Percentage share cost of control					63.00%
Expected environmental cost					$ 400.0
Regional Haze Rules \| Four Corners Units 4 and 5 \| Four Corners \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost					$ 45.0
Regional Haze Rules \| Four Corners Units 4 and 5 \| Natural Gas Tolling Letter of Credit \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional percentage share of cost of control					7.00%
Coal Combustion Waste \| Four Corners \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost					$ 22.0
Coal Combustion Waste \| Navajo Generating Station \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost					1.0
Coal Combustion Waste \| Cholla and Four Corners \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost					5.0
Coal Combustion Waste \| Minimum \| Cholla \| ARIZONA PUBLIC SERVICE COMPANY
Environmental Matters [Abstract]
Additional expected environment cost					$ 20.0
El Paso's Interest in Four Corners \| 4CA
Financial Assurances
Ownership interest acquired (as a percent)				7.00%	7.00%

Asset Retirement Obligations (Details) - ARIZONA PUBLIC SERVICE COMPANY - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations
Newly incurred or acquired obligations	$ 17,864	$ 0
ARO, decrease	1,000
Change in asset retirement obligations
Asset retirement obligations at the beginning of year	679,529	624,475
Changes attributable to:
Accretion expense	36,876	33,104
Settlements	(9,726)	0
Estimated cash flow revisions	2,002	21,950
Newly incurred or acquired obligations	17,864	0
Asset retirement obligations at the end of year	726,545	679,529
Solar Panels
Asset Retirement Obligations
Newly incurred or acquired obligations	14,000
Changes attributable to:
Newly incurred or acquired obligations	14,000
4CA
Asset Retirement Obligations
ARO, decrease	9,000
Navajo Generating Station
Asset Retirement Obligations
Newly incurred or acquired obligations		22,000
Increase in regulatory asset		2,000
Decrease in regulatory liability		20,000
Changes attributable to:
Newly incurred or acquired obligations		$ 22,000
Consumer Solar Panels
Asset Retirement Obligations
Newly incurred or acquired obligations	7,000
Changes attributable to:
Newly incurred or acquired obligations	$ 7,000

Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Selected Quarterly Financial Information [Line Items]
OPERATING REVENUES	$ 756,376	$ 1,268,034	$ 974,123	$ 692,714	$ 759,659	$ 1,183,322	$ 944,587	$ 677,728	$ 3,691,247	$ 3,565,296	$ 3,498,682
Operations and maintenance	256,120	246,545	268,397	265,682	271,212	230,839	220,985	226,071	1,036,744	949,107	931,692
Operating income	66,884	433,307	242,162	31,334	85,547	459,548	297,257	67,411	773,687	909,763	835,611
Income taxes	6,795	84,333	44,039	(1,265)	20,775	144,319	88,967	4,211	133,902	258,272	236,411
Net income	30,949	319,885	171,612	8,094	26,502	280,945	172,317	28,185	530,540	507,949	461,527
Net income attributable to common shareholders	$ 26,076	$ 315,012	$ 166,738	$ 3,221	$ 21,629	$ 276,072	$ 167,443	$ 23,312	$ 511,047	$ 488,456	$ 442,034
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders - basic (in dollars per share)	$ 0.23	$ 2.81	$ 1.49	$ 0.03	$ 0.19	$ 2.47	$ 1.50	$ 0.21	$ 4.56	$ 4.37	$ 3.97
Net income attributable to common shareholders — diluted (in dollars per share)	$ 0.23	$ 2.80	$ 1.48	$ 0.03	$ 0.19	$ 2.46	$ 1.49	$ 0.21	$ 4.54	$ 4.35	$ 3.95
ARIZONA PUBLIC SERVICE COMPANY
Selected Quarterly Financial Information [Line Items]
OPERATING REVENUES	$ 756,376	$ 1,267,997	$ 971,963	$ 692,006	$ 757,811	$ 1,178,846	$ 943,406	$ 677,589	$ 3,688,342	$ 3,557,652	$ 3,498,090
Operations and maintenance	236,281	226,346	251,999	254,601	260,826	222,374	215,775	219,008	969,227	917,983	902,467
Operating income	86,753	453,547	251,590	37,878	91,912	465,658	296,700	70,269	829,768	924,539	858,485
Income taxes									144,814	269,168	245,842
Net income									589,758	523,802	481,634
Net income attributable to common shareholders	$ 44,475	$ 338,366	$ 177,825	$ 9,599	$ 27,783	$ 284,256	$ 169,108	$ 23,162	$ 570,265	$ 504,309	$ 462,141

Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Assets
Cash equivalents	$ 1,200	$ 10,630
Other	(2,029)	(4,737)
Derivative assets	1,113	1,982
Other	398,953	417,499
Nuclear decommissioning trust	851,134	871,000
Other special use funds, gross fair value	236,101	32,542
Other special use funds, other	593	525
Other	397,517	413,287
Total assets	1,089,548	916,154
Liabilities
Other	875	1,516
Derivative Liability	(60,037)	(96,422)
Cash and cash equivalents
Assets
Other		109
Nuclear decommissioning trust		7,333
Equity securities
Assets
Other	2,148
Nuclear decommissioning trust	7,351
Other special use funds, gross fair value	45,723
Other special use funds, other	593
US commingled equity funds
Assets
Other	396,805	417,390
Nuclear decommissioning trust	396,805	417,390
U.S. Treasury debt
Assets
Nuclear decommissioning trust	148,173	127,662
Other special use funds, gross fair value	173,310
Corporate debt
Assets
Nuclear decommissioning trust	96,656	114,007
Mortgage-backed securities
Assets
Nuclear decommissioning trust	113,115	111,874
Municipal bonds
Assets
Nuclear decommissioning trust	79,073	79,049
Other special use funds, gross fair value	17,068
Other
Assets
Nuclear decommissioning trust	9,961	13,685
Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets
Cash equivalents	1,200	10,630
Decommissioning fund investments, gross fair value	153,376	134,886
Other special use funds, gross fair value	218,440	455
Total assets	373,016	145,971
Liabilities
Gross derivative liability	0	0
Quoted Prices in Active Markets for Identical Assets (Level 1) \| Cash and cash equivalents
Assets
Nuclear decommissioning trust		7,224
Quoted Prices in Active Markets for Identical Assets (Level 1) \| Equity securities
Assets
Nuclear decommissioning trust	5,203
Other special use funds, gross fair value	45,130
Quoted Prices in Active Markets for Identical Assets (Level 1) \| U.S. Treasury debt
Assets
Decommissioning fund investments, gross fair value	148,173	127,662
Other special use funds, gross fair value	173,310
Quoted Prices in Active Markets for Identical Assets (Level 1) \| Municipal bonds
Assets
Other special use funds, gross fair value	0
Significant Other Observable Inputs (Level 2)
Assets
Gross derivative assets	3,140	5,683
Decommissioning fund investments, gross fair value	298,805	318,615
Other special use funds, gross fair value	17,068	31,562
Total assets	319,013	355,860
Liabilities
Gross derivative liability	(52,696)	(78,646)
Significant Other Observable Inputs (Level 2) \| Equity securities
Assets
Other special use funds, gross fair value	0
Significant Other Observable Inputs (Level 2) \| U.S. Treasury debt
Assets
Other special use funds, gross fair value	0
Significant Other Observable Inputs (Level 2) \| Corporate debt
Assets
Decommissioning fund investments, gross fair value	96,656	114,007
Significant Other Observable Inputs (Level 2) \| Mortgage-backed securities
Assets
Decommissioning fund investments, gross fair value	113,115	111,874
Significant Other Observable Inputs (Level 2) \| Municipal bonds
Assets
Decommissioning fund investments, gross fair value	79,073	79,049
Other special use funds, gross fair value	17,068
Significant Other Observable Inputs (Level 2) \| Other
Assets
Decommissioning fund investments, gross fair value	9,961	13,685
Significant Unobservable Inputs (Level 3)
Assets
Gross derivative assets	2	1,036
Other special use funds, gross fair value	0
Total assets	2	1,036
Liabilities
Gross derivative liability	(8,216)	$ (19,292)
Significant Unobservable Inputs (Level 3) \| Equity securities
Assets
Other special use funds, gross fair value	0
Significant Unobservable Inputs (Level 3) \| U.S. Treasury debt
Assets
Other special use funds, gross fair value	0
Significant Unobservable Inputs (Level 3) \| Municipal bonds
Assets
Other special use funds, gross fair value	$ 0

Fair Value Measurements - Level 3 Quantitative Information (Details) $ in Thousands	Dec. 31, 2018 USD ($) $ / MWh	Dec. 31, 2017 USD ($) $ / MWh
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 1,113	$ 1,982
Forward Contracts \| Electricity forward contracts \| Minimum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) \| $ / MWh	17.88	18.51
Forward Contracts \| Electricity forward contracts \| Maximum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) \| $ / MWh	37.03	38.75
Forward Contracts \| Electricity forward contracts \| Weighted-Average
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) \| $ / MWh	26.10	27.89
Forward Contracts \| Natural gas forward contracts \| Minimum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) \| $ / MWh	1.79	2.33
Forward Contracts \| Natural gas forward contracts \| Maximum
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) \| $ / MWh	2.92	3.11
Forward Contracts \| Natural gas forward contracts \| Weighted-Average
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Electricity forward price (per MWh) \| $ / MWh	2.48	2.71
Forward Contracts \| Significant Unobservable Inputs (Level 3)
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	$ 2	$ 1,036
Liabilities	8,216	19,292
Forward Contracts \| Significant Unobservable Inputs (Level 3) \| Electricity forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	0	21
Liabilities	2,456	15,485
Forward Contracts \| Significant Unobservable Inputs (Level 3) \| Natural gas forward contracts
Information regarding the entity's internally developed significant unobservable inputs used to value its level 3 instruments
Assets	2	1,015
Liabilities	$ 5,760	$ 3,807

Fair Value Measurements - Changes in Fair Value of Risk Management Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Total net gains (losses) realized/unrealized:
Net derivative beginning balance	$ (18,256)	$ (47,406)
Included in earnings	0	0
Included in OCI	0	3
Deferred as a regulatory asset or liability	(1,130)	(13,643)
Settlements	(787)	5,834
Transfers into Level 3 from Level 2	(12,830)	(10,026)
Transfers from Level 3 into Level 2	24,789	46,982
Net derivative ending balance	(8,214)	(18,256)
Net unrealized gains included in earnings related to instruments still held at end of period	$ 0	$ 0

Fair Value Measurements - Additional Information (Details)	12 Months Ended
	Dec. 31, 2018 USD ($)
Fair Value Disclosures [Abstract]
Significant level 1 transfers	$ 0
Interest rate (as a percent)	3.90%
Financing receivable	$ 61,000,000

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 26,076	$ 315,012	$ 166,738	$ 3,221	$ 21,629	$ 276,072	$ 167,443	$ 23,312	$ 511,047	$ 488,456	$ 442,034
Weighted Average common shares outstanding — basic (in shares)									112,129	111,839	111,409
Net effect of dilutive securities:
Contingently issuable performance shares and restricted stock units									421	528	637
Weighted average common shares outstanding — diluted (in shares)									112,550	112,367	112,046
Earnings per average common share attributable to common shareholders — basic (in dollars per share)	$ 0.23	$ 2.81	$ 1.49	$ 0.03	$ 0.19	$ 2.47	$ 1.50	$ 0.21	$ 4.56	$ 4.37	$ 3.97
Earnings per average common share attributable to common shareholders — diluted (in dollars per share)	$ 0.23	$ 2.80	$ 1.48	$ 0.03	$ 0.19	$ 2.46	$ 1.49	$ 0.21	$ 4.54	$ 4.35	$ 3.95

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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-URI http://asc.fasb.org/extlink&oid=109260490&loc=SL5780133-109256

+ Details