PINNACLE WEST CAPITAL CORP, 10-Q filed on 5/1/2019
Quarterly Report
v3.19.1
Document and Entity Information - shares
3 Months Ended
Mar. 31, 2019
Apr. 24, 2019
Entity Information [Line Items]    
Entity Registrant Name PINNACLE WEST CAPITAL CORPORATION  
Entity Central Index Key 0000764622  
Document Type 10-Q  
Document Period End Date Mar. 31, 2019  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Large Accelerated Filer  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Common Stock, Shares Outstanding   112,277,359
Document Fiscal Year Focus 2019  
Document Fiscal Period Focus Q1  
APS    
Entity Information [Line Items]    
Entity Registrant Name ARIZONA PUBLIC SERVICE COMPANY  
Entity Central Index Key 0000007286  
Document Type 10-Q  
Document Period End Date Mar. 31, 2019  
Amendment Flag false  
Current Fiscal Year End Date --12-31  
Entity Current Reporting Status Yes  
Entity Filer Category Non-accelerated Filer  
Entity Emerging Growth Company false  
Entity Small Business false  
Entity Common Stock, Shares Outstanding   71,264,947
Document Fiscal Year Focus 2019  
Document Fiscal Period Focus Q1  
v3.19.1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($)
shares in Thousands, $ in Thousands
3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
OPERATING REVENUES $ 740,530 $ 692,714
OPERATING EXPENSES    
Fuel and purchased power 230,588 197,110
Operations and maintenance 245,634 265,682
Depreciation and amortization 148,707 144,825
Taxes other than income taxes 55,090 53,600
Other expenses 427 163
Total 680,446 661,380
OPERATING INCOME 60,084 31,334
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 11,188 14,079
Pension and other postretirement non-service credits - net 5,114 12,859
Other income (Note 9) 7,169 3,985
Other expense (Note 9) (4,358) (3,229)
Total 19,113 27,694
INTEREST EXPENSE    
Interest charges 60,653 58,954
Allowance for borrowed funds used during construction (6,665) (6,755)
Total 53,988 52,199
INCOME BEFORE INCOME TAXES 25,209 6,829
INCOME TAXES 2,418 (1,265)
NET INCOME 22,791 8,094
Less: Net income attributable to noncontrolling interests (Note 6) 4,873 4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 17,918 $ 3,221
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING    
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - BASIC (in shares) 112,337 112,017
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING - DILUTED (in shares) 112,735 112,493
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING    
Net income attributable to common shareholders - basic (in dollars per share) $ 0.16 $ 0.03
Net income attributable to common shareholders - diluted (in dollars per share) $ 0.16 $ 0.03
APS    
OPERATING REVENUES $ 740,530 $ 692,006
OPERATING EXPENSES    
Fuel and purchased power 230,588 202,010
Operations and maintenance 240,375 254,601
Depreciation and amortization 148,685 144,112
Taxes other than income taxes 55,078 53,242
Other expenses 427 163
Total 675,153 654,128
OPERATING INCOME 65,377 37,878
OTHER INCOME (DEDUCTIONS)    
Allowance for equity funds used during construction 11,188 14,079
Pension and other postretirement non-service credits - net 5,499 13,197
Other income (Note 9) 6,416 3,772
Other expense (Note 9) (3,878) (2,945)
Total 19,225 28,103
INTEREST EXPENSE    
Interest charges 56,665 56,158
Allowance for borrowed funds used during construction (6,665) (6,755)
Total 50,000 49,403
INCOME BEFORE INCOME TAXES 34,602 16,578
INCOME TAXES 1,453 2,106
NET INCOME 33,149 14,472
Less: Net income attributable to noncontrolling interests (Note 6) 4,873 4,873
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 28,276 $ 9,599
v3.19.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
NET INCOME $ 22,791 $ 8,094
Derivative instruments:    
Net unrealized gain (loss), net of tax expense 0 (96)
Reclassification of net realized loss, net of tax expense 328 409
Pension and other postretirement benefits activity, net of tax benefit 879 900
Total other comprehensive income 1,207 1,213
COMPREHENSIVE INCOME 23,998 9,307
Less: Comprehensive income attributable to noncontrolling interests 4,873 4,873
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS 19,125 4,434
APS    
NET INCOME 33,149 14,472
Derivative instruments:    
Net unrealized gain (loss), net of tax expense 0 (96)
Reclassification of net realized loss, net of tax expense 328 409
Pension and other postretirement benefits activity, net of tax benefit 752 857
Total other comprehensive income 1,080 1,170
COMPREHENSIVE INCOME 34,229 15,642
Less: Comprehensive income attributable to noncontrolling interests 4,873 4,873
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 29,356 $ 10,769
v3.19.1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Net unrealized loss, tax expense $ 0 $ 96
Reclassification of net realized loss, tax expense (benefit) 108 82
Pension and other postretirement (benefits) activity, tax benefit (expense) 288 443
APS    
Net unrealized loss, tax expense 0 96
Reclassification of net realized loss, tax expense (benefit) 108 82
Pension and other postretirement (benefits) activity, tax benefit (expense) $ 247 $ 306
v3.19.1
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($)
$ in Thousands
Mar. 31, 2019
Dec. 31, 2018
CURRENT ASSETS    
Cash and cash equivalents $ 6,109 $ 5,766
Customer and other receivables 249,568 267,887
Accrued unbilled revenues 114,077 137,170
Allowance for doubtful accounts (2,455) (4,069)
Materials and supplies (at average cost) 280,857 269,065
Fossil fuel (at average cost) 26,294 25,029
Assets from risk management activities (Note 7) 763 1,113
Deferred fuel and purchased power regulatory asset (Note 4) 7,583 37,164
Other regulatory assets (Note 4) 127,642 129,738
Other current assets 65,951 56,128
Total current assets 876,389 924,991
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 11 and 12) 919,309 851,134
Other special use funds (Notes 11 and 12) 238,207 236,101
Other assets 99,446 103,247
Total investments and other assets 1,256,962 1,190,482
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 18,763,499 18,736,628
Accumulated depreciation and amortization (6,398,512) (6,366,014)
Net 12,364,987 12,370,614
Construction work in progress 1,233,018 1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 104,808 105,775
Intangible assets, net of accumulated amortization 267,998 262,902
Nuclear fuel, net of accumulated amortization 142,610 120,217
Total property, plant and equipment 14,113,421 14,029,570
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,321,507 1,342,941
Operating lease right-of-use assets (Note 16) 193,897 0
Assets for other postretirement benefits (Note 5) 52,674 46,906
Other 39,257 129,312
Total deferred debits 1,607,335 1,519,159
TOTAL ASSETS 17,854,107 17,664,202
CURRENT LIABILITIES    
Accounts payable 263,656 277,336
Accrued taxes 199,949 154,819
Accrued interest 50,074 61,107
Common dividends payable 0 82,675
Short-term borrowings (Note 3) 244,050 76,400
Current maturities of long-term debt (Note 3) 250,000 500,000
Customer deposits 87,263 91,174
Liabilities from risk management activities (Note 7) 33,289 35,506
Liabilities for asset retirements 22,823 19,842
Operating lease liabilities (Note 16) 65,435 0
Regulatory liabilities (Note 4) 260,404 165,876
Other current liabilities 114,361 184,229
Total current liabilities 1,591,304 1,648,964
DEFERRED CREDITS AND OTHER    
Deferred income taxes 1,811,689 1,807,421
Regulatory liabilities (Note 4) 2,272,082 2,325,976
Liabilities for asset retirements 712,885 706,703
Liabilities for pension benefits (Note 5) 384,492 443,170
Liabilities from risk management activities (Note 7) 14,844 24,531
Customer advances 155,894 137,153
Coal mine reclamation 214,037 212,785
Deferred investment tax credit 200,052 200,405
Unrecognized tax benefits 26,042 22,517
Operating lease liabilities (Note 16) 53,704 0
Other 149,249 147,640
Total deferred credits and other 5,994,970 6,028,301
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY    
Common stock, no par value; authorized 150,000,000 shares, 112,340,322 and 112,159,896 issued at respective dates 2,644,063 2,634,265
Treasury stock at cost; 63,271 and 58,135 shares at respective dates (5,586) (4,825)
Total common stock 2,638,477 2,629,440
Retained earnings 2,659,086 2,641,183
Accumulated other comprehensive loss (46,501) (47,708)
Total shareholders’ equity 5,251,062 5,222,915
Noncontrolling interests (Note 6) 130,663 125,790
Total equity 5,381,725 5,348,705
Long-term debt less current maturities (Note 3) 4,886,108 4,638,232
TOTAL LIABILITIES AND EQUITY 17,854,107 17,664,202
APS    
CURRENT ASSETS    
Cash and cash equivalents 6,080 5,707
Customer and other receivables 238,270 257,654
Accrued unbilled revenues 114,077 137,170
Allowance for doubtful accounts (2,455) (4,069)
Materials and supplies (at average cost) 280,857 269,065
Fossil fuel (at average cost) 26,294 25,029
Assets from risk management activities (Note 7) 763 1,113
Deferred fuel and purchased power regulatory asset (Note 4) 7,583 37,164
Other regulatory assets (Note 4) 127,642 129,738
Other current assets 44,417 35,111
Total current assets 843,528 893,682
INVESTMENTS AND OTHER ASSETS    
Nuclear decommissioning trust (Notes 11 and 12) 919,309 851,134
Other special use funds (Notes 11 and 12) 238,207 236,101
Other assets 42,090 40,817
Total investments and other assets 1,199,606 1,128,052
PROPERTY, PLANT AND EQUIPMENT    
Plant in service and held for future use 18,760,012 18,733,142
Accumulated depreciation and amortization (6,395,265) (6,362,771)
Net 12,364,747 12,370,371
Construction work in progress 1,233,018 1,170,062
Palo Verde sale leaseback, net of accumulated depreciation (Note 6) 104,808 105,775
Intangible assets, net of accumulated amortization 267,842 262,746
Nuclear fuel, net of accumulated amortization 142,610 120,217
Total property, plant and equipment 14,113,025 14,029,171
DEFERRED DEBITS    
Regulatory assets (Note 4) 1,321,507 1,342,941
Operating lease right-of-use assets (Note 16) 191,957 0
Assets for other postretirement benefits (Note 5) 48,961 43,212
Other 38,299 128,265
Total deferred debits 1,600,724 1,514,418
TOTAL ASSETS 17,756,883 17,565,323
CURRENT LIABILITIES    
Accounts payable 257,124 266,277
Accrued taxes 230,591 176,357
Accrued interest 47,585 60,228
Common dividends payable 0 82,700
Short-term borrowings (Note 3) 157,500 0
Current maturities of long-term debt (Note 3) 250,000 500,000
Customer deposits 87,263 91,174
Liabilities from risk management activities (Note 7) 33,289 35,506
Liabilities for asset retirements 22,823 19,842
Operating lease liabilities (Note 16) 65,267 0
Regulatory liabilities (Note 4) 260,404 165,876
Other current liabilities 114,665 178,137
Total current liabilities 1,526,511 1,576,097
DEFERRED CREDITS AND OTHER    
Deferred income taxes 1,815,368 1,812,664
Regulatory liabilities (Note 4) 2,272,082 2,325,976
Liabilities for asset retirements 712,885 706,703
Liabilities for pension benefits (Note 5) 367,296 425,404
Liabilities from risk management activities (Note 7) 14,844 24,531
Customer advances 155,894 137,153
Coal mine reclamation 214,037 212,785
Deferred investment tax credit 200,052 200,405
Unrecognized tax benefits 42,084 41,861
Operating lease liabilities (Note 16) 51,805 0
Other 125,844 125,511
Total deferred credits and other 5,972,191 6,012,993
COMMITMENTS AND CONTINGENCIES (SEE NOTE 8)
EQUITY    
Total common stock 178,162 178,162
Additional paid-in capital 2,721,696 2,721,696
Retained earnings 2,816,532 2,788,256
Accumulated other comprehensive loss (26,027) (27,107)
Total shareholders’ equity 5,690,363 5,661,007
Noncontrolling interests (Note 6) 130,663 125,790
Total equity 5,821,026 5,786,797
Long-term debt less current maturities (Note 3) 4,437,155 4,189,436
Total capitalization 10,258,181 9,976,233
TOTAL LIABILITIES AND EQUITY $ 17,756,883 $ 17,565,323
v3.19.1
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares
Mar. 31, 2019
Dec. 31, 2018
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]    
Common stock, par value (in dollars per share)
Common stock, authorized shares (in shares) 150,000,000 150,000,000
Common stock, issued shares (in shares) 112,340,322 112,159,896
Treasury stock at cost, shares (in shares) 63,271 58,135
v3.19.1
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($)
$ in Thousands
3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME $ 22,791 $ 8,094
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 167,801 163,566
Deferred fuel and purchased power 16,709 (18,950)
Deferred fuel and purchased power amortization 12,872 20,002
Allowance for equity funds used during construction (11,188) (14,079)
Deferred income taxes 3,620 (229)
Deferred investment tax credit (353) (147)
Stock compensation 12,074 10,537
Changes in current assets and liabilities:    
Customer and other receivables 15,476 89,518
Accrued unbilled revenues 23,093 (6,555)
Materials, supplies and fossil fuel (13,057) (16,607)
Other current assets (10,115) (664)
Accounts payable 26,593 (25,738)
Accrued taxes 45,130 45,984
Other current liabilities (86,250) (12,030)
Change in other long-term assets (65,470) (3,765)
Change in other long-term liabilities 13,706 (72,065)
Net cash flow provided by operating activities 173,432 166,872
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (259,792) (361,037)
Contributions in aid of construction 7,938 8,569
Allowance for borrowed funds used during construction (6,665) (6,755)
Proceeds from nuclear decommissioning trust sales and other special use funds 179,048 130,456
Investment in nuclear decommissioning trust and other special use funds (179,618) (131,027)
Other 4,576 (1,299)
Net cash flow used for investing activities (254,513) (361,093)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 497,324 0
Short-term borrowing and payments — net 172,650 263,500
Short-term debt borrowings under revolving credit facility 0 36,000
Short-term debt repayments under revolving credit facility (5,000) (25,000)
Dividends paid on common stock (80,897) (75,903)
Repayment of long-term debt (500,000) 0
Common stock equity issuance - net of purchases (2,653) (2,828)
Net cash flow provided by financing activities 81,424 195,769
NET INCREASE IN CASH AND CASH EQUIVALENTS 343 1,548
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 5,766 13,892
CASH AND CASH EQUIVALENTS AT END OF PERIOD 6,109 15,440
Supplemental disclosure of cash flow information    
Income taxes, net of refunds 1 0
Interest, net of amounts capitalized 63,764 56,026
Significant non-cash investing and financing activities:    
Accrued capital expenditures 95,879 86,991
APS    
CASH FLOWS FROM OPERATING ACTIVITIES    
NET INCOME 33,149 14,472
Adjustments to reconcile net income to net cash provided by operating activities:    
Depreciation and amortization including nuclear fuel 167,779 162,853
Deferred fuel and purchased power 16,709 (18,950)
Deferred fuel and purchased power amortization 12,872 20,002
Allowance for equity funds used during construction (11,188) (14,079)
Deferred income taxes (1,205) 533
Deferred investment tax credit (353) (147)
Changes in current assets and liabilities:    
Customer and other receivables 16,541 90,647
Accrued unbilled revenues 23,093 (6,555)
Materials, supplies and fossil fuel (13,057) (16,747)
Other current assets (9,598) (1,237)
Accounts payable 30,774 (24,592)
Accrued taxes 54,234 54,106
Other current liabilities (81,627) (15,771)
Change in other long-term assets (64,516) 3,722
Change in other long-term liabilities 14,525 (70,928)
Net cash flow provided by operating activities 188,132 177,329
CASH FLOWS FROM INVESTING ACTIVITIES    
Capital expenditures (259,446) (355,039)
Contributions in aid of construction 7,938 8,569
Allowance for borrowed funds used during construction (6,665) (6,755)
Proceeds from nuclear decommissioning trust sales and other special use funds 179,048 130,456
Investment in nuclear decommissioning trust and other special use funds (179,618) (131,027)
Other (1,140) (1,183)
Net cash flow used for investing activities (259,883) (354,979)
CASH FLOWS FROM FINANCING ACTIVITIES    
Issuance of long-term debt 497,324 0
Short-term borrowing and payments — net 157,500 255,500
Short-term debt borrowings under revolving credit facility 0 25,000
Short-term debt repayments under revolving credit facility 0 (25,000)
Dividends paid on common stock (82,700) (77,700)
Repayment of long-term debt (500,000) 0
Net cash flow provided by financing activities 72,124 177,800
NET INCREASE IN CASH AND CASH EQUIVALENTS 373 150
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 5,707 13,851
CASH AND CASH EQUIVALENTS AT END OF PERIOD 6,080 14,001
Supplemental disclosure of cash flow information    
Income taxes, net of refunds 0 0
Interest, net of amounts capitalized 61,387 54,873
Significant non-cash investing and financing activities:    
Accrued capital expenditures $ 95,879 $ 86,944
v3.19.1
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($)
$ in Thousands
Total
Common Stock
Treasury Stock
Retained Earnings
Accumulated Other Comprehensive Income (Loss)
Noncontrolling Interests
APS
APS
Common Stock
APS
Additional Paid-In Capital
APS
Retained Earnings
APS
Accumulated Other Comprehensive Income (Loss)
APS
Noncontrolling Interests
Beginning balance (in shares) at Dec. 31, 2017   111,816,170 64,463         71,264,947        
Balance at beginning of period 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
Increase (Decrease) in Shareholders' Equity                        
Net income 8,094     3,221   4,873 14,472     9,599   4,873
Other comprehensive income 1,213       1,213   1,170       1,170  
Other             1         1
Dividends on common stock (16)     (16)                
Issuance of common stock (in shares)   145,793                    
Issuance of common stock 5,456 $ 5,456                    
Purchase of treasury stock (in shares) [1]     (81,177)                  
Purchase of treasury stock [1] (6,277)   $ (6,277)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     116,543                  
Reissuance of treasury stock for stock-based compensation and other 9,471   $ 9,470 0   1            
Reclassification of income tax effects related to new tax reform (8,552)     8,552 [2] (8,552) [2]   (5,038)     5,038 [2] (5,038) [2]  
Ending balance (in shares) at Mar. 31, 2018   111,961,963 29,097         71,264,947        
Balance at end of period at Mar. 31, 2018 $ 5,153,671 $ 2,620,261 $ (2,431) 2,454,268 (52,341) 133,914 5,401,512 $ 178,162 2,571,696 2,548,591 (30,851) 133,914
Beginning balance (in shares) at Dec. 31, 2018 112,159,896 112,159,896 58,135         71,264,947        
Balance at beginning of period 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
Increase (Decrease) in Shareholders' Equity                        
Net income 22,791     17,918   4,873 33,149     28,276   4,873
Other comprehensive income 1,207       1,207   1,080       1,080  
Dividends on common stock (15)     (15)                
Issuance of common stock (in shares)   180,426                    
Issuance of common stock 9,798 $ 9,798                    
Purchase of treasury stock (in shares) [1]     (75,791)                  
Purchase of treasury stock [1] (6,882)   $ (6,882)                  
Reissuance of treasury stock for stock-based compensation and other (in shares)     70,655                  
Reissuance of treasury stock for stock-based compensation and other $ 6,121   $ 6,121 0   0            
Ending balance (in shares) at Mar. 31, 2019 112,340,322 112,340,322 63,271         71,264,947        
Balance at end of period at Mar. 31, 2019 $ 5,381,725 $ 2,644,063 $ (5,586) $ 2,659,086 $ (46,501) $ 130,663 $ 5,821,026 $ 178,162 $ 2,721,696 $ 2,816,532 $ (26,027) $ 130,663
[1] Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
[2] In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) on items within accumulated other comprehensive income to retained earnings.
v3.19.1
Consolidation and Nature of Operations
3 Months Ended
Mar. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Consolidation and Nature of Operations Consolidation and Nature of Operations
 
The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS, 4C Acquisition, LLC ("4CA"), Bright Canyon Energy Corporation ("BCE") and El Dorado Investment Company ("El Dorado").  See Note 8 for more information on 4CA matters. Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Generating Station ("Palo Verde") sale leaseback variable interest entities ("VIEs") (see Note 6 for further discussion).  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.
 
Amounts reported in our interim Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods, due to the effects of seasonal temperature variations on energy consumption, timing of maintenance on electric generating units, and other factors.
 
Our condensed 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. Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading. The accompanying condensed consolidated financial statements and these notes should be read in conjunction with the audited consolidated financial statements and notes included in our 2018 Form 10-K.

Supplemental Cash Flow Information

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):
 
Three Months Ended 
 March 31,
 
2019
 
2018
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$
1

 
$

Interest, net of amounts capitalized
63,764

 
56,026

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
95,879

 
$
86,991

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
2,293

 



The following table summarizes supplemental APS cash flow information (dollars in thousands):
 
Three Months Ended 
 March 31,
 
2019
 
2018
Cash paid during the period for:
 
 
 
Income taxes, net of refunds
$

 
$

Interest, net of amounts capitalized
61,387

 
54,873

Significant non-cash investing and financing activities:
 
 
 
Accrued capital expenditures
$
95,879

 
$
86,944

Right-of-use operating lease assets obtained in exchange for operating lease liabilities
2,293

 

v3.19.1
Revenue
3 Months Ended
Mar. 31, 2019
Revenue from Contract with Customer [Abstract]  
Revenue Revenue

Sources of Revenue

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 United States Federal Energy Regulatory Commission ("FERC").

    
The following table provides detail of Pinnacle West's consolidated revenue disaggregated by revenue sources (dollars in thousands):
 
 
Three Months Ended March 31,
 
 
2019
 
2018
Retail residential electric service
 
$
351,566

 
$
316,675

Retail non-residential electric service
 
332,668

 
343,189

Wholesale energy sales
 
36,452

 
12,089

Transmission services for others
 
15,249

 
14,845

Other sources
 
4,595

 
5,916

Total operating revenues
 
$
740,530

 
$
692,714


    
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 three months ended March 31, 2019 and 2018 were $721 million and $683 million, respectively.

We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the three months ended March 31, 2019 and 2018, our revenues that do not qualify as revenue from contracts with customers were $20 million and $10 million, respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. See Note 4 for a discussion of our regulatory cost recovery mechanisms.

Contract Assets and Liabilities from Contracts with Customers

There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Condensed Consolidated Balance Sheets as of March 31, 2019 or December 31, 2018.
v3.19.1
Long-Term Debt and Liquidity Matters
3 Months Ended
Mar. 31, 2019
Debt Disclosure [Abstract]  
Long-Term Debt and Liquidity Matters Long-Term Debt and Liquidity Matters

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.
 
Pinnacle West
 
At March 31, 2019, Pinnacle West had a 364-day $150 million revolving credit facility that matures June 27, 2019.  Borrowings under the facility bear interest at LIBOR plus 0.70% per annum. At March 31, 2019, Pinnacle West had $49 million in outstanding borrowings under the facility.

At March 31, 2019, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West's senior unsecured debt credit ratings. The facility is available to support Pinnacle West's $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At March 31, 2019,
Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $38 million of commercial paper borrowings.

APS

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

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

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

At March 31, 2019, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023.  APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders.  Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At March 31, 2019, APS had $158 million of commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities.
 
See "Financial Assurances" in Note 8 for a discussion of APS’s other outstanding letters of credit.
 
Debt Fair Value
 
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table presents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):

 
As of March 31, 2019
 
As of December 31, 2018
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Pinnacle West
$
448,953

 
$
446,835

 
$
448,796

 
$
443,955

APS
4,687,155

 
4,942,057

 
4,689,436

 
4,789,608

Total
$
5,136,108

 
$
5,388,892

 
$
5,138,232

 
$
5,233,563

v3.19.1
Regulatory Matters
3 Months Ended
Mar. 31, 2019
Regulated Operations [Abstract]  
Regulatory Matters 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. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the "2017 Settlement Agreement") and filed it with the ACC. The 2017 Settlement
Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54%).

Other key provisions of the agreement include the following:

an agreement by APS not to file another general retail rate case application before June 1, 2019;
an authorized return on common equity of 10.0%;
a capital structure comprised of 44.2% debt and 55.8% common equity;
a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;
a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing selective catalytic reduction ("SCR") equipment at the Four Corners Power Plant ("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 Power Supply Adjustor (“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 distributed generation with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the Arizona Renewable Energy Standard and Tariff ("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 distributed generation ("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. On April 9, 2019, the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. On April 22, 2019, the Administrative Law Judge issued a proposed amendment to the Recommended Opinion and Order which proposes that APS credit back to customers the $5 million Demand Side Management Adjustor Charge ("DSMAC") funds used by APS to educate ratepayers on the new rates and that APS ratepayers will be held harmless from expenditures made by APS for targeted outreach and education in any future rate case. 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.  On April 23, 2019, the ACC Staff indicated that they may need some additional time beyond May 3, 2019 to file the requested report. APS does not believe that the rate review will have a material impact on our current 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 reopening the 2017 Rate Case Decision.  APS cannot predict the outcome of this matter.

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

On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million.  APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request 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 including a waiver of the distributed energy requirements for the 2018 implementation year.

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

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

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

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

 Power Supply Adjustor Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset (liability) for 2019 and 2018 (dollars in thousands):
 
 
Three Months Ended 
 March 31,
 
2019
 
2018
Beginning balance
$
37,164

 
$
75,637

Deferred fuel and purchased power costs — current period
(16,709
)
 
18,950

Amounts charged to customers
(12,872
)
 
(20,002
)
Ending balance
$
7,583

 
$
74,585


 
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 ("TCA") 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 settlement agreement entered into in 2012 regarding APS's rate case (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.

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.

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.

 Lost Fixed Cost Recovery Mechanism.  The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were first established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost. These amounts were revised in the 2017 Settlement Agreement to 2.5 cents for both lost residential and non-residential kWh.  The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWhs lost from energy
efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  DG sales losses are determined from the metered output from the DG units.
 
APS filed its 2017 LFCR adjustment on January 13, 2017 requesting an LFCR adjustment of $63.7 million. 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). The ACC has not yet ruled on APS’s 2019 LFCR adjustment request. 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 ("TEAM").  As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. The TEAM expressly applies to APS's retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. On December 22, 2017, the Tax Act was enacted.  This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.

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

The impact of the TEAM Phase I, over time, is expected to be earnings neutral. However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM Phase I related to the lower federal income tax rate. The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in revenues refunded through the TEAM Phase I is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company.

On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers ("TEAM Phase II"). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019. The impact of TEAM Phase II is expected to be earnings neutral as both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit are recognized based upon our seasonal kWh sales pattern.
    
On April 10, 2019, APS filed a third request with the ACC that addresses the amortization of depreciation related excess deferred taxes over a 28.5 year period (“TEAM Phase III”).  Over the first 36 months, TEAM Phase III is expected to return $34.5 million to customers annually, and APS has proposed this refund begin July 1, 2019.  The Company is currently in the process of seeking IRS guidance affirming the amortization method and period applicable to these depreciation related excess deferred taxes. The ACC has not yet approved TEAM Phase III.
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, 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, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Arizona Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these
appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.

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.

Information Requests from Arizona Corporation Commissioners

On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West. In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC. On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018. Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019. APS received subsequent requests on these matters and continues to respond to such follow-on requests. Pinnacle West and APS cannot predict the outcome of these matters.

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 integrated resource plans ("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 July 5, 2018, ACC Commissioner Tobin’s office issued a set of draft CREST rules for the ACC’s consideration, which proposes an electricity generating portfolio of at least 80% clean energy sources (including nuclear generation) by 2050, a target of 3,000 megawatts of deployed energy storage by 2030, and a plan to implement a new Energy Efficiency Standard when the current standard sunsets in 2020.

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. On April 25, 2019, the ACC Staff issued a set of draft rules in regards to the Energy Modernization Plan and workshops were held on April 29, 2019 regarding these draft rules. On April 26, 2019, Commissioner Dunn issued a proposed set of rules with regards to the Energy Modernization Plan. 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. On February 25, 2019, APS filed a request to extend the deadline to file its Preliminary Integrated Resource Plan from April 1, 2019 to August 1, 2019.  On April 24, 2019, the ACC approved this request.

Four Corners 

SCE-Related Matters. On December 30, 2013, APS purchased Southern California Edison Company's ("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 $46 million as of March 31, 2019 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. Oral argument for this proceeding is scheduled for May 15, 2019. 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, however we cannot predict the outcome of the decision. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).
  
Cholla

On September 11, 2014, APS announced that it would close Unit 2 of the Cholla Power Plant ("Cholla") and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if the United States Environmental Protection Agency ("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 ($85 million as of March 31, 2019), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2026.
On March 20, 2019, APS announced that it has begun evaluating the feasibility and cost of converting a unit at the Cholla to burn biomass. Biomass is a fuel comprised of forest trimmings, and a converted unit at Cholla could assist in forest thinning, responsible forest management, an improved watershed, and a reduced wildfire risk. APS’s ability to operate a biomass power plant would depend on third-parties procuring forest biomass for fuel. APS will report the result of its evaluation by May 20, 2019. If converting a unit is more cost effective than alternatives, APS will seek ACC approval before moving forward with the Cholla conversion project. APS cannot predict the outcome of this matter.
Navajo Plant
The co-owners of the Navajo Generating Station (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.

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 ($85 million as of March 31, 2019) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material. APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS's remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS's net income, cash flows, and financial position will be negatively impacted.    

Regulatory Assets and Liabilities 
The detail of regulatory assets is as follows (dollars in thousands): 
 
Amortization Through
 
March 31, 2019
 
December 31, 2018
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Pension
(a)
 
$

 
$
723,307

 
$

 
$
733,351

Retired power plant costs
2033
 
28,182

 
160,167

 
28,182

 
167,164

Income taxes — allowance for funds used during construction ("AFUDC") equity
2049
 
6,457

 
151,541

 
6,457

 
151,467

Deferred fuel and purchased power — mark-to-market (Note 7)
2023
 
29,340

 
14,360

 
31,728

 
23,768

Deferred fuel and purchased power (b) (c)
2020
 
7,583

 

 
37,164

 

Four Corners cost deferral
2024
 
8,077

 
38,209

 
8,077

 
40,228

Income taxes — investment tax credit basis adjustment
2047
 
1,079

 
25,475

 
1,079

 
25,522

Lost fixed cost recovery (b)
2020
 
29,698

 

 
32,435

 

Palo Verde VIEs (Note 6)
2046
 

 
20,170

 

 
20,015

Deferred compensation
2036
 

 
37,581

 

 
36,523

Deferred property taxes
2027
 
8,569

 
64,214

 
8,569

 
66,356

Loss on reacquired debt
2038
 
1,637

 
13,259

 
1,637

 
13,668

Tax expense of Medicare subsidy
2024
 
1,235

 
6,122

 
1,235

 
6,176

TCA balancing account (b)
2020
 
306

 

 
3,860

 
772

AG-1 deferral
2022
 
2,654

 
5,155

 
2,654

 
5,819

Mead-Phoenix transmission line CIAC
2050
 
332

 
9,961

 
332

 
10,044

Coal reclamation
2026
 
1,546

 
17,392

 
1,546

 
15,607

SCR deferral
N/A
 

 
30,581

 

 
23,276

Tax expense adjuster mechanism (c)
2019
 
5,451

 

 

 

Other
Various
 
3,079

 
4,013

 
1,947

 
3,185

Total regulatory assets (d)
 
 
$
135,225

 
$
1,321,507

 
$
166,902

 
$
1,342,941


(a)
This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to other comprehensive income ("OCI") and result in lower future revenues.
(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):
 
 
Amortization Through
 
March 31, 2019
 
December 31, 2018
 
 
Current
 
Non-Current
 
Current
 
Non-Current
Excess deferred income taxes - ACC - Tax Cuts and Jobs Act
(a)
 
$
91,401

 
$
1,178,216

 
$

 
$
1,272,709

Excess deferred income taxes - FERC - Tax Cuts and Jobs Act
2058
 
6,302

 
243,418

 
6,302

 
243,691

Asset retirement obligations
2057
 

 
337,844

 

 
278,585

Removal costs
(b)
 
50,701

 
156,578

 
39,866

 
177,533

Other postretirement benefits
(c)
 
37,864

 
116,478

 
37,864

 
125,903

Income taxes — deferred investment tax credit
2047
 
2,164

 
51,027

 
2,164

 
51,120

Income taxes — change in rates
2048
 
2,764

 
69,954

 
2,769

 
70,069

Spent nuclear fuel
2027
 
7,190

 
54,866

 
6,503

 
57,002

Renewable energy standard (a)
2020
 
47,943

 

 
44,966

 
20

Demand side management (a)
2020
 
1,581

 
24,146

 
14,604

 
4,123

Sundance maintenance
2030
 
6,657

 
11,637

 
1,278

 
17,228

Deferred gains on utility property
2022
 
3,923

 
5,975

 
4,423

 
6,581

Four Corners coal reclamation
2038
 
1,858

 
17,690

 
1,858

 
17,871

Tax expense adjustor mechanism (a)
2020
 
14

 

 
3,237

 

Other
Various
 
42

 
4,253

 
42

 
3,541

Total regulatory liabilities
 
 
$
260,404

 
$
2,272,082

 
$
165,876

 
$
2,325,976


(a)
See “Cost Recovery Mechanisms” discussion above.
(b)
In accordance with regulatory accounting guidance, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(c)
See Note 5.
v3.19.1
Retirement Plans and Other Postretirement Benefits
3 Months Ended
Mar. 31, 2019
Retirement Benefits [Abstract]  
Retirement Plans and Other Postretirement Benefits Retirement Plans and Other Postretirement Benefits
 
Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and an other postretirement benefit plan for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement dates.

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 Benefits
Other Benefits
 
Three Months Ended 
 March 31,
 
Three Months Ended 
 March 31,
 
2019
 
2018
 
2019
 
2018
Service cost — benefits earned during the period
$
12,543

 
$
14,213

 
$
4,714

 
$
5,105

Non-service costs (credits):
 
 
 
 
 
 
 
Interest cost on benefit obligation
34,352

 
31,007

 
7,526

 
7,101

Expected return on plan assets
(42,893
)
 
(45,667
)
 
(9,603
)
 
(10,520
)
  Amortization of:
 

 
 
 
 

 
 

  Prior service cost (credit)

 

 
(9,455
)
 
(9,461
)
  Net actuarial loss
11,239

 
7,782

 

 

Net periodic benefit cost (credit)
$
15,241

 
$
7,335

 
$
(6,818
)
 
$
(7,775
)
Portion of cost (credit) charged to expense
$
8,244

 
$
2,242

 
$
(4,817
)
 
$
(5,605
)

 
Contributions
 
We have made voluntary contributions of $90 million to our pension plan year-to-date in 2019. 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. We do not expect to make any contributions over the next three years to our other postretirement benefit plans.
v3.19.1
Palo Verde Sale Leaseback Variable Interest Entities
3 Months Ended
Mar. 31, 2019
Variable Interest Entities [Abstract]  
Palo Verde Sale Leaseback Variable Interest Entities 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 through 2023, and $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 for the three months ended March 31, 2019 and 2018 of $5 million, entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.

Our Condensed Consolidated Balance Sheets at March 31, 2019 and December 31, 2018 include the following amounts relating to the VIEs (dollars in thousands):
 
 
March 31, 2019
 
December 31, 2018
Palo Verde sale leaseback property plant and equipment, net of accumulated depreciation
$
104,808

 
$
105,775

Equity — Noncontrolling interests
130,663

 
125,790


 
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our condensed consolidated financial statements.
 
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur.  Under certain circumstances (for example, the Nuclear Regulatory Commission ("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 $299 million beginning in 2019, and up to $456 million over the lease extension terms.
 
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
v3.19.1
Derivative Accounting
3 Months Ended
Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Accounting Derivative Accounting
 
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, emissions allowances, and in 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 Condensed 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 sheets as an asset or liability and are measured at fair value.  See Note 11 for a discussion of fair value measurements.  Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business.  Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
 
For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income.  Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4).  Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
 
As of March 31, 2019 and December 31, 2018, we had the following outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position): 
 
 
 
Quantity
Commodity
 
Unit of Measure
March 31, 2019
 
December 31, 2018
Power
 
GWh
1,146

 
250

Gas
 
Billion cubic feet
233

 
218


 
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 three months ended March 31, 2019 and 2018 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2019
 
2018
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
 
Fuel and purchased power (b)
 
$
(436
)
 
$
(491
)

(a)
During the three months ended March 31, 2019 and 2018, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)
Amounts are before the effect of PSA deferrals.
 
During the next twelve months, we estimate that a net loss of $1 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 three months ended March 31, 2019 and 2018 (dollars in thousands):
 
 
 
Financial Statement Location
 
Three Months Ended 
 March 31,
Commodity Contracts
 
 
2019
 
2018
Net Loss Recognized in Income
 
Operating revenues
 
$

 
$
(1,219
)
Net Gain (Loss) Recognized in Income
 
Fuel and purchased power (a)
 
8,170

 
(34,089
)
Total
 
 
 
$
8,170

 
$
(35,308
)

(a)
Amounts are before the effect of PSA deferrals.
 
Derivative Instruments in the Condensed 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 Condensed Consolidated Balance Sheets.  Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Condensed 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.
 
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 March 31, 2019 and December 31, 2018.  These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Condensed Consolidated Balance Sheets.

As of March 31, 2019:
(dollars in thousands)
 
Gross
 Recognized
 Derivatives
 (a)
 
Amounts
Offset
 (b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount Reported on Balance Sheets
Current assets
 
$
3,658

 
$
(2,857
)
 
$
801

 
$
(38
)
 
$
763

Investments and other assets
 
1,016

 
(881
)
 
135

 

 
135

Total assets
 
4,674

 
(3,738
)
 
936

 
(38
)
 
898

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(34,487
)
 
2,857

 
(31,630
)
 
(1,659
)
 
(33,289
)
Deferred credits and other
 
(15,725
)
 
881

 
(14,844
)
 

 
(14,844
)
Total liabilities
 
(50,212
)
 
3,738

 
(46,474
)
 
(1,659
)
 
(48,133
)
Total
 
$
(45,538
)
 
$

 
$
(45,538
)
 
$
(1,697
)
 
$
(47,235
)

(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 $1,659 and cash margin provided to counterparties of ($38).

As of December 31, 2018:
(dollars in thousands)
 
Gross
Recognized
Derivatives
 (a)
 
Amounts
Offset
(b)
 
Net
 Recognized
 Derivatives
 
Other
 (c)
 
Amount
Reported on
Balance Sheets
Current assets
 
$
3,106

 
$
(2,149
)
 
$
957

 
$
156

 
$
1,113

Investments and other assets
 
36

 
(36
)
 

 

 

Total assets
 
3,142

 
(2,185
)
 
957

 
156

 
1,113

 
 
 
 
 
 
 
 
 
 
 
Current liabilities
 
(36,345
)
 
2,149

 
(34,196
)
 
(1,310
)
 
(35,506
)
Deferred credits and other
 
(24,567
)
 
36

 
(24,531
)
 

 
(24,531
)
Total liabilities
 
(60,912
)
 
2,185

 
(58,727
)
 
(1,310
)
 
(60,037
)
Total
 
$
(57,770
)
 
$

 
$
(57,770
)
 
$
(1,154
)
 
$
(58,924
)

(a)
All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)
No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)
Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.

Credit Risk and Credit Related Contingent Features
 
We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of March 31, 2019, Pinnacle West has no counterparties with positive exposures of greater than 10% of risk management assets. Our risk management process assesses and monitors the financial exposure of all counterparties.  Despite the fact that the great majority of our trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies.  We maintain credit policies that we believe minimize overall credit risk to within acceptable limits.  Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition.  To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
 
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions.  Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions.  For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
 
The following table provides information about our derivative instruments that have credit-risk-related contingent features at March 31, 2019 (dollars in thousands):