Cover Page
Cover Page - shares | 6 Months Ended | |
Jun. 30, 2019 | Aug. 01, 2019 | |
Cover page. | ||
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Jun. 30, 2019 | |
Document Transition Report | false | |
Entity File Number | 1-5924 | |
Entity Registrant Name | TUCSON ELECTRIC POWER CO | |
Entity Incorporation, State or Country Code | AZ | |
Entity Tax Identification Number | 86-0062700 | |
Entity Address, Address Line One | 88 East Broadway Boulevard | |
Entity Address, City or Town | Tucson | |
Entity Address, State or Province | AZ | |
Entity Address, Postal Zip Code | 85701 | |
City Area Code | 520 | |
Local Phone Number | 571-4000 | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 32,139,434 | |
Entity Central Index Key | 0000100122 | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Year Focus | 2019 | |
Document Fiscal Period Focus | Q2 | |
Amendment Flag | false |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Income Statement [Abstract] | ||||
Operating Revenues | $ 326,091 | $ 354,246 | $ 659,094 | $ 629,336 |
Operating Expenses | ||||
Fuel | 75,441 | 62,870 | 164,859 | 130,893 |
Purchased Power | 27,345 | 32,389 | 60,195 | 52,753 |
Transmission and Other PPFAC Recoverable Costs | 12,094 | 9,909 | 24,019 | 19,700 |
Increase (Decrease) to Reflect PPFAC Recovery Treatment | (10,918) | 13,372 | (4,713) | 5,406 |
Total Fuel and Purchased Power | 103,962 | 118,540 | 244,360 | 208,752 |
Operations and Maintenance | 92,045 | 93,445 | 178,633 | 176,601 |
Depreciation | 41,427 | 39,418 | 82,744 | 78,294 |
Amortization | 7,397 | 6,021 | 15,014 | 12,042 |
Taxes Other Than Income Taxes | 14,120 | 14,299 | 28,321 | 28,479 |
Total Operating Expenses | 258,951 | 271,723 | 549,072 | 504,168 |
Operating Income | 67,140 | 82,523 | 110,022 | 125,168 |
Other Income (Expense) | ||||
Interest Expense | (22,144) | (16,707) | (44,275) | (33,192) |
Allowance For Borrowed Funds | 1,303 | 706 | 2,577 | 1,393 |
Allowance For Equity Funds | 3,398 | 1,532 | 6,721 | 3,177 |
Other, Net | 842 | 1,679 | 4,130 | 1,255 |
Total Other Income (Expense) | (16,601) | (12,790) | (30,847) | (27,367) |
Income Before Income Tax Expense | 50,539 | 69,733 | 79,175 | 97,801 |
Income Tax Expense | 8,476 | 12,136 | 10,917 | 16,401 |
Net Income | $ 42,063 | $ 57,597 | $ 68,258 | $ 81,400 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Statement of Comprehensive Income [Abstract] | ||||
Net Income | $ 42,063 | $ 57,597 | $ 68,258 | $ 81,400 |
Net Changes in Fair Value of Cash Flow Hedges: | ||||
Net of Income Tax Expense | 24 | 96 | 52 | 219 |
Supplemental Executive Retirement Plan Adjustments: | ||||
Net of Income Tax Expense | 66 | 117 | 132 | 232 |
Total Other Comprehensive Income, Net of Tax | 90 | 213 | 184 | 451 |
Total Comprehensive Income | $ 42,153 | $ 57,810 | $ 68,442 | $ 81,851 |
CONDENSED CONSOLIDATED STATEM_3
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Statement of Comprehensive Income [Abstract] | ||||
Tax Expense Related to Change in Fair Value of Cash Flow Hedges | $ 8 | $ 32 | $ 17 | $ 73 |
Tax Expense Related to Supplemental Executive Retirement Plan Adjustments | $ 22 | $ 39 | $ 44 | $ 79 |
CONDENSED CONSOLIDATED STATEM_4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Cash Flows from Operating Activities | ||
Net Income | $ 68,258 | $ 81,400 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | ||
Depreciation Expense | 82,744 | 78,294 |
Amortization Expense | 15,014 | 12,042 |
Amortization of Debt Issuance Costs | 1,153 | 1,168 |
Use of Renewable Energy Credits for Compliance | 18,624 | 15,132 |
Deferred Income Taxes | 14,244 | 21,924 |
Pension and Other Postretirement Benefits Expense | 8,881 | 7,668 |
Pension and Other Postretirement Benefits Funding | (6,431) | (5,708) |
Allowance for Equity Funds Used During Construction | (6,721) | (3,177) |
Regulatory Deferral, ACC Refund Order | 3,156 | 0 |
Changes in Current Assets and Current Liabilities: | ||
Accounts Receivable | 5,910 | (41,534) |
Materials, Supplies, and Fuel Inventory | (4,689) | 8,102 |
Regulatory Assets | (151) | (5,008) |
Other Current Assets | 1,766 | (1,677) |
Accounts Payable and Accrued Charges | (32,061) | 16,385 |
Income Taxes Receivable | (3,326) | (5,521) |
Regulatory Liabilities | (4,507) | 17,180 |
Other, Net | 969 | 1,117 |
Net Cash Flows—Operating Activities | 162,833 | 197,787 |
Cash Flows from Investing Activities | ||
Capital Expenditures | (199,791) | (174,810) |
Purchase Intangibles, Renewable Energy Credits | (24,793) | (25,848) |
Contributions in Aid of Construction | 3,932 | 7,773 |
Net Cash Flows—Investing Activities | (220,652) | (192,885) |
Cash Flows from Financing Activities | ||
Proceeds from Borrowings, Revolving Credit Facility | 0 | 66,000 |
Repayments of Borrowings, Revolving Credit Facility | 0 | (93,000) |
Payments of Finance Lease Obligations | (10,889) | (10,930) |
Other, Net | (166) | (3) |
Net Cash Flows—Financing Activities | (11,055) | (37,933) |
Net Decrease in Cash, Cash Equivalents, and Restricted Cash | (68,874) | (33,031) |
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 152,747 | 49,501 |
Cash, Cash Equivalents, and Restricted Cash, End of Period | $ 83,873 | $ 16,470 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands | Jun. 30, 2019 | Dec. 31, 2018 |
Utility Plant | ||
Plant in Service | $ 6,126,496 | $ 6,020,469 |
Utility Plant Under Finance Leases | 248,635 | 248,635 |
Construction Work in Progress | 298,115 | 258,965 |
Total Utility Plant | 6,673,246 | 6,528,069 |
Accumulated Depreciation and Amortization | (2,337,169) | (2,293,783) |
Accumulated Amortization of Finance Lease Assets | (79,829) | (73,646) |
Total Utility Plant, Net | 4,256,248 | 4,160,640 |
Investments and Other Property | 55,479 | 50,952 |
Current Assets | ||
Cash and Cash Equivalents | 69,692 | 138,114 |
Accounts Receivable, Net | 159,165 | 172,367 |
Fuel Inventory | 26,131 | 22,783 |
Materials and Supplies | 109,331 | 107,990 |
Regulatory Assets | 118,699 | 106,725 |
Derivative Instruments | 7,216 | 3,929 |
Other | 27,131 | 25,571 |
Total Current Assets | 517,365 | 577,479 |
Regulatory and Other Assets | ||
Regulatory Assets | 292,068 | 293,078 |
Derivative Instruments | 11,428 | 8,402 |
Other | 85,351 | 68,656 |
Total Regulatory and Other Assets | 388,847 | 370,136 |
Total Assets | 5,217,939 | 5,159,207 |
Capitalization | ||
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of June 30, 2019 and December 31, 2018) | 1,346,539 | 1,346,539 |
Capital Stock Expense | (6,357) | (6,357) |
Retained Earnings | 552,535 | 484,277 |
Accumulated Other Comprehensive Loss | (4,530) | (4,714) |
Total Common Stock Equity | 1,888,187 | 1,819,745 |
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2019 and December 31, 2018) | 0 | 0 |
Finance Lease Obligations | 6,192 | 19,773 |
Long-Term Debt, Net | 1,616,205 | 1,615,252 |
Total Capitalization | 3,510,584 | 3,454,770 |
Current Liabilities | ||
Finance Lease Obligations | 175,202 | 172,510 |
Accounts Payable | 105,712 | 133,012 |
Accrued Taxes Other than Income Taxes | 40,499 | 41,686 |
Accrued Employee Expenses | 25,393 | 34,339 |
Accrued Interest | 17,548 | 17,927 |
Regulatory Liabilities | 89,898 | 95,094 |
Customer Deposits | 25,191 | 27,650 |
Derivative Instruments | 31,242 | 18,137 |
Other | 24,204 | 21,555 |
Total Current Liabilities | 534,889 | 561,910 |
Regulatory and Other Liabilities | ||
Deferred Income Taxes, Net | 390,831 | 369,705 |
Regulatory Liabilities | 497,572 | 512,425 |
Pension and Other Postretirement Benefits | 116,306 | 117,472 |
Derivative Instruments | 29,868 | 19,361 |
Other | 137,889 | 123,564 |
Total Regulatory and Other Liabilities | 1,172,466 | 1,142,527 |
Commitments and Contingencies | ||
Total Capitalization and Other Liabilities | $ 5,217,939 | $ 5,159,207 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - shares | Jun. 30, 2019 | Dec. 31, 2018 |
Statement of Financial Position [Abstract] | ||
Common Stock, Shares Authorized (in shares) | 75,000,000 | 75,000,000 |
Common Stock, Shares Outstanding (in shares) | 32,139,434 | 32,139,434 |
Preferred Stock, Shares Authorized (in shares) | 1,000,000 | 1,000,000 |
Preferred Stock, Shares Outstanding (in shares) | 0 | 0 |
CONDENSED CONSOLIDATED STATEM_5
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - USD ($) $ in Thousands | Total | Common Stock | Capital Stock Expense | Retained Earnings | Accumulated Other Comprehensive Loss |
Beginning balance at Dec. 31, 2017 | $ 1,664,032 | $ 1,296,539 | $ (6,357) | $ 380,076 | $ (6,226) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 81,400 | 81,400 | |||
Other Comprehensive Income, Net of Tax | 451 | 451 | |||
Adoption of ASU, Cumulative Effect Adjustment | 0 | 878 | (878) | ||
Ending balance at Jun. 30, 2018 | 1,745,883 | 1,296,539 | (6,357) | 462,354 | (6,653) |
Beginning balance at Mar. 31, 2018 | 1,688,073 | 1,296,539 | (6,357) | 404,757 | (6,866) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 57,597 | 57,597 | |||
Other Comprehensive Income, Net of Tax | 213 | 213 | |||
Ending balance at Jun. 30, 2018 | 1,745,883 | 1,296,539 | (6,357) | 462,354 | (6,653) |
Beginning balance at Dec. 31, 2018 | 1,819,745 | 1,346,539 | (6,357) | 484,277 | (4,714) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 68,258 | 68,258 | |||
Other Comprehensive Income, Net of Tax | 184 | 184 | |||
Ending balance at Jun. 30, 2019 | 1,888,187 | 1,346,539 | (6,357) | 552,535 | (4,530) |
Beginning balance at Mar. 31, 2019 | 1,846,034 | 1,346,539 | (6,357) | 510,472 | (4,620) |
Increase (Decrease) in Stockholder's Equity [Roll Forward] | |||||
Net Income | 42,063 | 42,063 | |||
Other Comprehensive Income, Net of Tax | 90 | 90 | |||
Ending balance at Jun. 30, 2019 | $ 1,888,187 | $ 1,346,539 | $ (6,357) | $ 552,535 | $ (4,530) |
NATURE OF OPERATIONS AND FINANC
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION | 6 Months Ended |
Jun. 30, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION | NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 427,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis. BASIS OF PRESENTATION TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the SEC's interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2018 Annual Report on Form 10-K. The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation. Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. TEP routinely enters into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis. As of June 30, 2019 , the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. Restricted Cash Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement: Six Months Ended June 30, (in millions) 2019 2018 Cash and Cash Equivalents $ 70 $ 6 Restricted Cash included in: Investments and Other Property 13 9 Current Assets—Other 1 1 Total Cash, Cash Equivalents, and Restricted Cash $ 84 $ 16 Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs. NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures. Leases TEP adopted accounting guidance that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance has been applied on a prospective basis to all new or modified land easements since January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 6 for additional disclosure about TEP’s leasing arrangements. Internal-Use Software TEP early adopted accounting guidance that clarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively. NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures. |
REGULATORY MATTERS
REGULATORY MATTERS | 6 Months Ended |
Jun. 30, 2019 | |
Regulated Operations [Abstract] | |
REGULATORY MATTERS | REGULATORY MATTERS The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates the terms and prices of transmission services and wholesale electricity sales. 2019 ACC RATE CASE On April 1, 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018. The filing requests new rates be implemented by May 1, 2020. The key proposals of the rate case include: • a non-fuel retail revenue increase of $115 million , partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $76 million , or 7.8% , over test year retail revenues; • a 7.68% return on original cost rate base of $2.7 billion , which includes a cost of equity of 10.35% and an average cost of debt of 4.65% ; • a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the planned purchase of Gila River Unit 2 and the installation of RICE units at Sundt; • a TEAM rate that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and • a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC. TEP cannot predict the outcome of the proceeding. 2019 FERC RATE CASE On May 31, 2019, TEP filed a proposal with the FERC requesting revisions to its OATT. The filing requests that the proposed revisions be implemented by August 1, 2019. The key proposals of the filing include: • replacing TEP's stated transmission rates with a forward-looking formula rate; • a 10.4% return on equity; and • elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate. The requested forward-looking formula rate will allow for more timely recovery of transmission related costs. On July 31, 2019, FERC issued an order accepting TEP's proposed OATT revisions effective August 1, 2019, subject to refund, and established hearing and settlement procedures. TEP cannot predict the outcome of the proceeding. Abandoned Plant Costs Also on May 31, 2019, TEP filed with the FERC a request to recover through its OATT rates abandoned plant costs related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that it incurred in developing the transmission line. The filing requests that the abandoned plant costs be included in TEP's transmission rate. TEP cannot predict the outcome of this proceeding. As of June 30, 2019 , there was $4 million related to the Nogales transmission line recorded in Regulatory and Other Assets—Regulatory Assets on the Condensed Consolidated Balance Sheets. FEDERAL TAX LEGISLATION Arizona Corporation Commission In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of a customer bill credit and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018. The refund represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the following year's bill credit amounts. Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. The 2018 refund amount totaled $33 million . TEP filed an information filing with the ACC to establish a 2019 customer refund of $34 million . The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Beginning of Period $ 3 $ (7 ) $ 4 $ — ACC Refund (Reduction in Operating Revenues) (9 ) (10 ) (16 ) (17 ) Amount Returned to Customers through Bill Credits 6 12 10 12 Regulatory Deferral 1 — 3 — End of Period $ 1 $ (5 ) $ 1 $ (5 ) COST RECOVERY MECHANISMS TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below. Purchased Power and Fuel Adjustment Clause TEP's PPFAC rate is adjusted annually each April 1st and goes into effect for the subsequent 12 -month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12 -month period. The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Beginning of Period $ (22 ) $ (4 ) $ (17 ) $ (9 ) Deferred Fuel and Purchased Power Costs (1) 6 (11 ) 3 (9 ) PPFAC Refunds (Recoveries) (2) 7 (3 ) 5 — End of Period $ (9 ) $ (18 ) $ (9 ) $ (18 ) (1) The negative balance in Deferred Fuel and Purchased Power Costs represents a decrease in the actual cost of fuel and purchased power below the costs associated with base recoveries. (2) The ACC approved a PPFAC credit to begin returning the over-collected PPFAC balance to customers for the period of March 2017 through April 2018. In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request. Renewable Energy Standard The ACC’s RES requires Arizona regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement is 9% of retail electric sales in 2019 and increases annually until renewable retail sales represent at least 15% by 2025 , with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC. In January 2018, the ACC approved TEP's 2018 RES implementation plan with a budget amount of $54 million , which is recovered through the RES surcharge. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs. Energy Efficiency Standards TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards. The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million in 2019 and 2018 related to performance in Operating Revenues on the Condensed Consolidated Statements of Income. In February 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million , which is collected through the DSM surcharge. Lost Fixed Cost Recovery Mechanism The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of TEP's applicable retail revenues. The table below summarizes the LFCR revenues recognized in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 LFCR Revenues $ 6 $ 5 $ 16 $ 13 REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded on the balance sheet are summarized in the table below: ($ in millions) Remaining Recovery Period (years) June 30, 2019 December 31, 2018 Regulatory Assets Pension and Other Postretirement Benefits Various $ 123 $ 126 Early Generation Retirement Costs (1) Various 67 72 Derivatives (Note 9) 11 47 27 Income Taxes Recoverable through Future Rates (2) Various 44 47 Lost Fixed Cost Recovery 2 42 35 Final Mine Reclamation and Retiree Healthcare Costs (3) 19 26 29 Property Tax Deferrals (4) 1 24 23 Springerville Unit 1 Leasehold Improvements (5) 4 10 11 Other Regulatory Assets Various 28 30 Total Regulatory Assets 411 400 Less Current Portion 1 119 107 Total Non-Current Regulatory Assets $ 292 $ 293 Regulatory Liabilities Income Taxes Payable through Future Rates (2) Various $ 344 $ 354 Net Cost of Removal (6) Various 162 171 Renewable Energy Standard Various 53 52 Purchased Power and Fuel Adjustment Clause 1 9 17 Deferred Investment Tax Credits (7) Various 7 7 Other Regulatory Liabilities Various 13 6 Total Regulatory Liabilities 588 607 Less Current Portion 1 90 95 Total Non-Current Regulatory Liabilities $ 498 $ 512 (1) Includes the net book value and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Condensed Consolidated Balance Sheets due to the planned early retirement of the facilities. Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. TEP has requested recovery of final retirement costs of Navajo and Sundt Units 1 and 2 over a 10 -year period in the 2019 Rate Case. (2) Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA. (3) Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to recover these costs on a pay-as-you-go basis through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2038 . (4) Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months. (5) Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10 -year period. (6) Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, and generation plant and general and intangible plant, which are not yet expended. (7) Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset. Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs and Income Taxes Payable through Future Rates related to the EDIT balances, TEP does not pay a return on regulatory liabilities. |
REVENUE
REVENUE | 6 Months Ended |
Jun. 30, 2019 | |
Revenue from Contract with Customer [Abstract] | |
REVENUE | REVENUE DISAGGREGATION OF REVENUES TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Retail $ 236 $ 273 $ 438 $ 465 Wholesale 43 35 127 73 Other Services 30 27 54 50 Revenues from Contracts with Customers 309 335 619 588 Alternative Revenues 6 5 18 15 Other 11 14 22 26 Total Operating Revenues $ 326 $ 354 $ 659 $ 629 |
ACCOUNTS RECEIVABLE
ACCOUNTS RECEIVABLE | 6 Months Ended |
Jun. 30, 2019 | |
Receivables [Abstract] | |
ACCOUNTS RECEIVABLE | ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2019 December 31, 2018 Customer (1) $ 85 $ 99 Customer, Unbilled 59 45 Due from Affiliates (Note 5) 6 8 Other 14 25 Allowance for Doubtful Accounts (5 ) (5 ) Accounts Receivable, Net $ 159 $ 172 (1) Includes $3 million as of June 30, 2019 , and $8 million as of December 31, 2018 , of receivables related to revenue from derivative instruments. |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 6 Months Ended |
Jun. 30, 2019 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS TEP engages in various transactions with Fortis, UNS Energy, and the UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor related services. The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2019 December 31, 2018 Receivables from Related Parties UNS Electric $ 4 $ 7 UNS Gas 2 1 Total Due from Related Parties $ 6 $ 8 Payables to Related Parties SES $ 2 $ 2 UNS Energy 2 1 UNS Electric — 1 UNS Gas — 1 Total Due to Related Parties $ 4 $ 5 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 2 $ 1 $ 3 $ 3 Control Area Services, UNS Electric (2) 1 1 2 1 Common Costs, UNS Energy Affiliates (3) 5 5 10 9 Goods and Services Provided by Affiliates to TEP Supplemental Workforce, SES (4) 4 4 7 7 Corporate Services, UNS Energy (5) 2 1 3 3 Corporate Services, UNS Energy Affiliates (6) 1 1 2 3 (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable Open Access Transmission Tariff. (2) TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. (3) Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. (4) SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management. (5) Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 83% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $1 million and $3 million for the three and six months ended June 30, 2019 and 2018 , respectively. (6) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. DIVIDENDS PAID TO PARENT On July 22, 2019, TEP declared a $38 million dividend to UNS Energy which was paid July 30, 2019. |
LEASES
LEASES | 6 Months Ended |
Jun. 30, 2019 | |
Leases [Abstract] | |
LEASES | LEASES When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet. TEP leases generation facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises. TEP’s leases are included on the balance sheet as follows: (in millions) Lease Type June 30, 2019 Lease Assets Utility Plant Under Finance Leases Finance $ 249 Accumulated Amortization of Finance Lease Assets Finance (80 ) Regulatory and Other Assets, Other Operating 8 Lease Liabilities Current Liabilities, Finance Lease Obligations (1)(2) Finance 175 Finance Lease Obligations (2) Finance 6 Current Liabilities, Other Operating 1 Regulatory and Other Liabilities, Other Operating 7 (1) TEP recorded the fair value purchase price of Gila River Unit 2 as determined by SRP's 2018 purchase price. TEP expects to complete the purchase of Gila River Unit 2 in December 2019. (2) Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021. TEP may renew the two leases or exercise its remaining fixed-price purchase options. The following table presents the components of TEP’s lease cost: Three Months Ended Six Months Ended (in millions) June 30, 2019 Finance Amortization of Leased Assets $ 3 $ 6 Interest on Lease Liabilities (1) 3 6 Operating — 1 Variable 5 9 Total Lease Cost $ 11 $ 22 (1) Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. TEP has a 20 -year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020. As of June 30, 2019 , TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: (in millions) Finance Leases (1) Operating Leases Total 2019 $ 170 $ 1 $ 171 2020 20 1 21 2021 — 1 1 2022 — 1 1 2023 — 1 1 Thereafter — 5 5 Total Lease Payments 190 10 200 Less Imputed Interest 9 2 11 Total Lease Obligations 181 8 189 Less Current Portion 175 1 176 Total Non-Current Lease Obligations $ 6 $ 7 $ 13 (1) Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20 -month lease term. The following table presents TEP's lease terms and discount rate related to its leases: June 30, 2019 Weighted-Average Remaining Lease Term (years) Finance Leases 1 Operating Leases 12 Weighted-Average Discount Rate Finance Leases 7.1 % Operating Leases 4.1 % The following table presents TEP's cash flow information related to its leases: Six Months Ended (in millions) June 30, 2019 Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows used for Finance Leases $ 7 Financing Cash Flows used for Finance Leases 11 Right-of-Use Assets Obtained in Exchange for New Lease Liabilities Operating Leases 8 Operating cash flows from operating leases for the six months ended June 30, 2019 , were no t material. In addition, TEP leases limited office facilities and utility property to others with remaining terms of three to five years . Most leases include one or more options to renew, with renewal terms that may extend the lease term for two to ten years . Operating lease income for the three and six months ended June 30, 2019 , was not material to TEP's results of operations. TEP's expected operating lease payments to be received as of June 30, 2019 , are $1 million in each of 2019 through 2023 and thereafter. DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD As of December 31, 2018 , future minimum lease payments were as follows: (in millions) Capital Leases Operating Leases 2019 $ 187 $ 1 2020 20 1 2021 — 1 2022 — 1 2023 — 1 Thereafter — 5 Total Lease Payments 207 $ 10 Less: Imputed Interest 14 Total Lease Obligations 193 Less: Current Portion 173 Total Non-Current Lease Obligations $ 20 Operating lease cost for the three and six months ended June 30, 2018 , was no t material to TEP's results of operations. The following table presents TEP's non-cash investing information related to its leases: Six Months Ended (in millions) June 30, 2018 Assets Obtained in Exchange for New Lease Liabilities Capital Leases $ 165 In May 2018, TEP recorded an increase to both capital lease assets and liabilities related to the 20 -year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The Tolling PPA includes a three-year option to purchase the unit. The amount reflects the fair value of the unit as determined by SRP's purchase price. |
LEASES | LEASES When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet. TEP leases generation facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises. TEP’s leases are included on the balance sheet as follows: (in millions) Lease Type June 30, 2019 Lease Assets Utility Plant Under Finance Leases Finance $ 249 Accumulated Amortization of Finance Lease Assets Finance (80 ) Regulatory and Other Assets, Other Operating 8 Lease Liabilities Current Liabilities, Finance Lease Obligations (1)(2) Finance 175 Finance Lease Obligations (2) Finance 6 Current Liabilities, Other Operating 1 Regulatory and Other Liabilities, Other Operating 7 (1) TEP recorded the fair value purchase price of Gila River Unit 2 as determined by SRP's 2018 purchase price. TEP expects to complete the purchase of Gila River Unit 2 in December 2019. (2) Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021. TEP may renew the two leases or exercise its remaining fixed-price purchase options. The following table presents the components of TEP’s lease cost: Three Months Ended Six Months Ended (in millions) June 30, 2019 Finance Amortization of Leased Assets $ 3 $ 6 Interest on Lease Liabilities (1) 3 6 Operating — 1 Variable 5 9 Total Lease Cost $ 11 $ 22 (1) Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. TEP has a 20 -year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020. As of June 30, 2019 , TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: (in millions) Finance Leases (1) Operating Leases Total 2019 $ 170 $ 1 $ 171 2020 20 1 21 2021 — 1 1 2022 — 1 1 2023 — 1 1 Thereafter — 5 5 Total Lease Payments 190 10 200 Less Imputed Interest 9 2 11 Total Lease Obligations 181 8 189 Less Current Portion 175 1 176 Total Non-Current Lease Obligations $ 6 $ 7 $ 13 (1) Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20 -month lease term. The following table presents TEP's lease terms and discount rate related to its leases: June 30, 2019 Weighted-Average Remaining Lease Term (years) Finance Leases 1 Operating Leases 12 Weighted-Average Discount Rate Finance Leases 7.1 % Operating Leases 4.1 % The following table presents TEP's cash flow information related to its leases: Six Months Ended (in millions) June 30, 2019 Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows used for Finance Leases $ 7 Financing Cash Flows used for Finance Leases 11 Right-of-Use Assets Obtained in Exchange for New Lease Liabilities Operating Leases 8 Operating cash flows from operating leases for the six months ended June 30, 2019 , were no t material. In addition, TEP leases limited office facilities and utility property to others with remaining terms of three to five years . Most leases include one or more options to renew, with renewal terms that may extend the lease term for two to ten years . Operating lease income for the three and six months ended June 30, 2019 , was not material to TEP's results of operations. TEP's expected operating lease payments to be received as of June 30, 2019 , are $1 million in each of 2019 through 2023 and thereafter. DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD As of December 31, 2018 , future minimum lease payments were as follows: (in millions) Capital Leases Operating Leases 2019 $ 187 $ 1 2020 20 1 2021 — 1 2022 — 1 2023 — 1 Thereafter — 5 Total Lease Payments 207 $ 10 Less: Imputed Interest 14 Total Lease Obligations 193 Less: Current Portion 173 Total Non-Current Lease Obligations $ 20 Operating lease cost for the three and six months ended June 30, 2018 , was no t material to TEP's results of operations. The following table presents TEP's non-cash investing information related to its leases: Six Months Ended (in millions) June 30, 2018 Assets Obtained in Exchange for New Lease Liabilities Capital Leases $ 165 In May 2018, TEP recorded an increase to both capital lease assets and liabilities related to the 20 -year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The Tolling PPA includes a three-year option to purchase the unit. The amount reflects the fair value of the unit as determined by SRP's purchase price. |
LEASES | LEASES When a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet. TEP leases generation facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises. TEP’s leases are included on the balance sheet as follows: (in millions) Lease Type June 30, 2019 Lease Assets Utility Plant Under Finance Leases Finance $ 249 Accumulated Amortization of Finance Lease Assets Finance (80 ) Regulatory and Other Assets, Other Operating 8 Lease Liabilities Current Liabilities, Finance Lease Obligations (1)(2) Finance 175 Finance Lease Obligations (2) Finance 6 Current Liabilities, Other Operating 1 Regulatory and Other Liabilities, Other Operating 7 (1) TEP recorded the fair value purchase price of Gila River Unit 2 as determined by SRP's 2018 purchase price. TEP expects to complete the purchase of Gila River Unit 2 in December 2019. (2) Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021. TEP may renew the two leases or exercise its remaining fixed-price purchase options. The following table presents the components of TEP’s lease cost: Three Months Ended Six Months Ended (in millions) June 30, 2019 Finance Amortization of Leased Assets $ 3 $ 6 Interest on Lease Liabilities (1) 3 6 Operating — 1 Variable 5 9 Total Lease Cost $ 11 $ 22 (1) Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. TEP has a 20 -year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020. As of June 30, 2019 , TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: (in millions) Finance Leases (1) Operating Leases Total 2019 $ 170 $ 1 $ 171 2020 20 1 21 2021 — 1 1 2022 — 1 1 2023 — 1 1 Thereafter — 5 5 Total Lease Payments 190 10 200 Less Imputed Interest 9 2 11 Total Lease Obligations 181 8 189 Less Current Portion 175 1 176 Total Non-Current Lease Obligations $ 6 $ 7 $ 13 (1) Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20 -month lease term. The following table presents TEP's lease terms and discount rate related to its leases: June 30, 2019 Weighted-Average Remaining Lease Term (years) Finance Leases 1 Operating Leases 12 Weighted-Average Discount Rate Finance Leases 7.1 % Operating Leases 4.1 % The following table presents TEP's cash flow information related to its leases: Six Months Ended (in millions) June 30, 2019 Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows used for Finance Leases $ 7 Financing Cash Flows used for Finance Leases 11 Right-of-Use Assets Obtained in Exchange for New Lease Liabilities Operating Leases 8 Operating cash flows from operating leases for the six months ended June 30, 2019 , were no t material. In addition, TEP leases limited office facilities and utility property to others with remaining terms of three to five years . Most leases include one or more options to renew, with renewal terms that may extend the lease term for two to ten years . Operating lease income for the three and six months ended June 30, 2019 , was not material to TEP's results of operations. TEP's expected operating lease payments to be received as of June 30, 2019 , are $1 million in each of 2019 through 2023 and thereafter. DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD As of December 31, 2018 , future minimum lease payments were as follows: (in millions) Capital Leases Operating Leases 2019 $ 187 $ 1 2020 20 1 2021 — 1 2022 — 1 2023 — 1 Thereafter — 5 Total Lease Payments 207 $ 10 Less: Imputed Interest 14 Total Lease Obligations 193 Less: Current Portion 173 Total Non-Current Lease Obligations $ 20 Operating lease cost for the three and six months ended June 30, 2018 , was no t material to TEP's results of operations. The following table presents TEP's non-cash investing information related to its leases: Six Months Ended (in millions) June 30, 2018 Assets Obtained in Exchange for New Lease Liabilities Capital Leases $ 165 In May 2018, TEP recorded an increase to both capital lease assets and liabilities related to the 20 -year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The Tolling PPA includes a three-year option to purchase the unit. The amount reflects the fair value of the unit as determined by SRP's purchase price. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 6 Months Ended |
Jun. 30, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES COMMITMENTS In addition to those reported in its 2018 Annual Report on Form 10-K, TEP entered into the following long-term commitment: In March 2019, TEP entered into an agreement to develop a wind-powered electric generation facility with estimated costs of approximately $370 million . TEP will own and operate the facility, which will be located in southeastern New Mexico and have a nominal capacity rating of 247 MW. Construction is expected to commence in 2019 and be completed by December 2020. CONTINGENCIES Legal Matters TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or consolidated financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts on TEP and are disclosed below. Claims Related to San Juan Generating Station WildEarth Guardians In 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the Office of Surface Mining Reclamation and Enforcement (OSMRE) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to Westmoreland San Juan Mining LLC's (as successor to San Juan Coal Company (SJCC)) existing San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSMRE, including: (i) failure to provide requisite public notice and participation, and (ii) failure to analyze certain environmental impacts. WEG’s petition seeks various forms of relief, including voiding and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the approvals until they can demonstrate compliance with the NEPA, and enjoining operations at the affected mines. SJCC intervened in this matter and was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now pending. In July 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSMRE so the OSMRE may prepare a new Environmental Impact Statement (EIS) under the NEPA regarding the impacts of the San Juan Mine mining plan approval. In August 2016, the court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provides that: (i) the OSMRE's decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 31, 2019, then the approved mine plan will immediately be vacated, absent further court order. In May 2018, the OSMRE released a draft EIS for public comment which was open through July 2018. On April 30, 2019, the OSMRE issued a final Record of Decision (ROD) on the Final EIS released March 15, 2019. The Final EIS contemplates continued mining at the San Juan Mine in annual quantities similar to those currently being provided through 2033. TEP plans to retire San Juan in 2022. The OSMRE's ROD is subject to approval by the Assistant Secretary for Land and Minerals Management. TEP cannot currently predict the outcome of this matter. Mine Reclamation at Generation Facilities Not Operated by TEP TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s estimated share of mine reclamation costs at all three mines is $63 million . Payments will be made through the expiration of the coal supply agreements, which expire between December 2019 and 2031 . An aggregate liability balance related to final mine reclamation of $36 million as of June 30, 2019 and December 31, 2018 , was reflected in current and non-current Other on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs. Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements. TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid out. Performance Guarantees TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and Luna. The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of June 30, 2019 , there have been no such payment defaults under any of the participation agreements. The participation agreements expire in: (i) December 2019 at Navajo; (ii) 2022 at San Juan; (iii) 2041 at Four Corners; and (iv) 2046 at Luna. Environmental Matters TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects. |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 6 Months Ended |
Jun. 30, 2019 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended June 30, (in millions) 2019 2018 2019 2018 Service Cost $ 3 $ 3 $ 1 $ 1 Non-Service Cost (1) Interest Cost 5 4 1 1 Expected Return on Plan Assets (7 ) (7 ) — — Amortization of Net Loss 2 2 — — Net Periodic Benefit Cost $ 3 $ 2 $ 2 $ 2 Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Service Cost $ 6 $ 7 $ 2 $ 2 Non-Service Cost (1) Interest Cost 9 8 1 1 Expected Return on Plan Assets (13 ) (14 ) — — Amortization of Net Loss 4 4 — — Net Periodic Benefit Cost $ 6 $ 5 $ 3 $ 3 (1) The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income. |
FAIR VALUE MEASUREMENTS AND DER
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | 6 Months Ended |
Jun. 30, 2019 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement: Level 1 Level 2 Level 3 Total (in millions) June 30, 2019 Assets Cash Equivalents (1) $ 67 $ — $ — $ 67 Restricted Cash (1) 14 — — 14 Energy Derivative Contracts, Regulatory Recovery (2) — 10 3 13 Energy Derivative Contracts, No Regulatory Recovery (2) — — 6 6 Total Assets 81 10 9 100 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (48 ) (13 ) (61 ) Total Liabilities — (48 ) (13 ) (61 ) Total Assets (Liabilities), Net $ 81 $ (38 ) $ (4 ) $ 39 (in millions) December 31, 2018 Assets Cash Equivalents (1) $ 125 $ — $ — $ 125 Restricted Cash (1) 15 — — 15 Energy Derivative Contracts, Regulatory Recovery (2) — 10 — 10 Energy Derivative Contracts, No Regulatory Recovery (2) — — 2 2 Total Assets 140 10 2 152 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (35 ) (2 ) (37 ) Total Liabilities — (35 ) (2 ) (37 ) Total Assets (Liabilities), Net $ 140 $ (25 ) $ — $ 115 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds, certificates of deposit, and insured cash sweep accounts valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets. (2) Energy Derivative Contracts include gas swap agreements (Level 2) and forward purchased power and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. In 2019, Derivative Contract Liabilities increased primarily due to increases in volume and decreases in forward market prices of natural gas. All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral. Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) June 30, 2019 Derivative Assets Energy Derivative Contracts $ 19 $ 13 $ — $ 6 Derivative Liabilities Energy Derivative Contracts (61 ) (13 ) — (48 ) (in millions) December 31, 2018 Derivative Assets Energy Derivative Contracts $ 12 $ 11 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (37 ) (11 ) — (26 ) DERIVATIVE INSTRUMENTS TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of the Company's retail customers. The Company primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used. For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The Company primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses. TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data. The inputs and the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly. Cash Flow Hedges To mitigate the exposure to volatility in variable interest rates on debt, TEP has an interest rate swap agreement that expires January 2020 . The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months and the realized loss recorded to Interest Expense are not material to TEP's financial position or results of operations. As of June 30, 2019 , the total notional amount of the interest rate swap was $6 million . Energy Derivative Contracts, Regulatory Recovery TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Unrealized Net Gain (Loss) $ (11 ) $ (14 ) $ (20 ) $ (32 ) Energy Derivative Contracts, No Regulatory Recovery TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Operating Revenues $ 5 $ 4 $ 5 $ 5 Derivative Volumes As of June 30, 2019 , TEP had energy contracts that will settle on various expiration dates through 2029 . The following table presents volumes associated with the energy contracts: June 30, 2019 December 31, 2018 Power Contracts GWh 5,836 1,743 Gas Contracts BBtu 138,837 146,933 Level 3 Fair Value Measurements The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Approach Fair Value of Unobservable Inputs Range of Unobservable Inputs Assets Liabilities (in millions) June 30, 2019 Forward Power Contracts Market approach $ 9 $ (13 ) Market price per MWh $ 17.05 $ 64.60 (in millions) December 31, 2018 Forward Power Contracts Market approach $ 3 $ (2 ) Market price per MWh $ 16.80 $ 47.05 Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement. The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Beginning of Period $ (6 ) $ 1 $ 1 $ 2 Gains (Losses) Recorded Regulatory Assets or Liabilities, Derivative Instruments (2 ) — (10 ) — Operating Revenues 5 4 5 4 Settlements (1 ) — — (1 ) End of Period $ (4 ) $ 5 $ (4 ) $ 5 Gains (Losses), Assets (Liabilities) Still Held $ 3 $ 6 $ (4 ) $ 5 CREDIT RISK The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. TEP enters into contracts for the physical delivery of power and natural gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurements at fair value. TEP has contractual agreements for energy procurement and hedging activities that contain certain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits; (ii) credit rating downgrades; or (iii) a failure to meet certain financial ratios. In the event that such credit events were to occur, the Company, or its counterparties, would have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts. TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the individual contracts. The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $84 million as of June 30, 2019 , compared with $41 million as of December 31, 2018 . As of June 30, 2019 , TEP had no collateral posted with its counterparties. If the credit risk contingent features were triggered on June 30, 2019 , TEP would have been required to post an additional $84 million of collateral of which $15 million relates to outstanding net payable balances for settled positions. FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Borrowings under revolving credit facilities approximate fair value due to the short-term nature of these financial instruments. These items have been excluded from the table below. The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the face value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Face Value Fair Value (in millions) June 30, 2019 December 31, 2018 June 30, 2019 December 31, 2018 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,629 $ 1,629 $ 1,745 $ 1,672 |
NATURE OF OPERATIONS AND FINA_2
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies) | 6 Months Ended |
Jun. 30, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of presentation | BASIS OF PRESENTATION TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the SEC's interim reporting requirements. The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities in the Condensed Consolidated Statements of Income. These Condensed Consolidated Financial Statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2018 Annual Report on Form 10-K. The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results. Certain amounts from prior periods have been reclassified to conform to the current period presentation. |
Variable interest entities | Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE, and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE. TEP routinely enters into long-term renewable PPAs with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis. As of June 30, 2019 , the carrying amounts of assets and liabilities in the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. |
Restricted cash | Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs. |
New accounting standards | NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures. Leases TEP adopted accounting guidance that requires lessees to recognize a lease liability, initially measured at the present value of future lease payments, and a right-of-use asset for all leases with a lease term greater than 12 months. The new lease standard also requires additional quantitative and qualitative disclosures for both lessees and lessors. TEP applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance has been applied on a prospective basis to all new or modified land easements since January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption. See Note 6 for additional disclosure about TEP’s leasing arrangements. Internal-Use Software TEP early adopted accounting guidance that clarifies accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively. NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures. |
NATURE OF OPERATIONS AND FINA_3
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of cash, cash equivalents | The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement: Six Months Ended June 30, (in millions) 2019 2018 Cash and Cash Equivalents $ 70 $ 6 Restricted Cash included in: Investments and Other Property 13 9 Current Assets—Other 1 1 Total Cash, Cash Equivalents, and Restricted Cash $ 84 $ 16 |
Schedule of restricted cash | The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement: Six Months Ended June 30, (in millions) 2019 2018 Cash and Cash Equivalents $ 70 $ 6 Restricted Cash included in: Investments and Other Property 13 9 Current Assets—Other 1 1 Total Cash, Cash Equivalents, and Restricted Cash $ 84 $ 16 |
REGULATORY MATTERS (Tables)
REGULATORY MATTERS (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Regulated Operations [Abstract] | |
Schedule of Regulatory Assets | The table below summarizes the regulatory asset (liability) balance related to the ACC Refund Order: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Beginning of Period $ 3 $ (7 ) $ 4 $ — ACC Refund (Reduction in Operating Revenues) (9 ) (10 ) (16 ) (17 ) Amount Returned to Customers through Bill Credits 6 12 10 12 Regulatory Deferral 1 — 3 — End of Period $ 1 $ (5 ) $ 1 $ (5 ) |
Schedule of Purchased Power and Fuel Adjustment Rates | The table below summarizes the PPFAC regulatory asset (liability) balance: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Beginning of Period $ (22 ) $ (4 ) $ (17 ) $ (9 ) Deferred Fuel and Purchased Power Costs (1) 6 (11 ) 3 (9 ) PPFAC Refunds (Recoveries) (2) 7 (3 ) 5 — End of Period $ (9 ) $ (18 ) $ (9 ) $ (18 ) (1) The negative balance in Deferred Fuel and Purchased Power Costs represents a decrease in the actual cost of fuel and purchased power below the costs associated with base recoveries. (2) The ACC approved a PPFAC credit to begin returning the over-collected PPFAC balance to customers for the period of March 2017 through April 2018. In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request. |
Schedule of Regulated Operating Revenue | The table below summarizes the LFCR revenues recognized in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 LFCR Revenues $ 6 $ 5 $ 16 $ 13 |
Schedule of Regulatory Assets and Liabilities | Regulatory assets and liabilities recorded on the balance sheet are summarized in the table below: ($ in millions) Remaining Recovery Period (years) June 30, 2019 December 31, 2018 Regulatory Assets Pension and Other Postretirement Benefits Various $ 123 $ 126 Early Generation Retirement Costs (1) Various 67 72 Derivatives (Note 9) 11 47 27 Income Taxes Recoverable through Future Rates (2) Various 44 47 Lost Fixed Cost Recovery 2 42 35 Final Mine Reclamation and Retiree Healthcare Costs (3) 19 26 29 Property Tax Deferrals (4) 1 24 23 Springerville Unit 1 Leasehold Improvements (5) 4 10 11 Other Regulatory Assets Various 28 30 Total Regulatory Assets 411 400 Less Current Portion 1 119 107 Total Non-Current Regulatory Assets $ 292 $ 293 Regulatory Liabilities Income Taxes Payable through Future Rates (2) Various $ 344 $ 354 Net Cost of Removal (6) Various 162 171 Renewable Energy Standard Various 53 52 Purchased Power and Fuel Adjustment Clause 1 9 17 Deferred Investment Tax Credits (7) Various 7 7 Other Regulatory Liabilities Various 13 6 Total Regulatory Liabilities 588 607 Less Current Portion 1 90 95 Total Non-Current Regulatory Liabilities $ 498 $ 512 (1) Includes the net book value and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Condensed Consolidated Balance Sheets due to the planned early retirement of the facilities. Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. TEP has requested recovery of final retirement costs of Navajo and Sundt Units 1 and 2 over a 10 -year period in the 2019 Rate Case. (2) Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA. (3) Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to recover these costs on a pay-as-you-go basis through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2038 . (4) Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months. (5) Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10 -year period. (6) Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, and generation plant and general and intangible plant, which are not yet expended. (7) Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset. |
REVENUE (Tables)
REVENUE (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Retail $ 236 $ 273 $ 438 $ 465 Wholesale 43 35 127 73 Other Services 30 27 54 50 Revenues from Contracts with Customers 309 335 619 588 Alternative Revenues 6 5 18 15 Other 11 14 22 26 Total Operating Revenues $ 326 $ 354 $ 659 $ 629 |
ACCOUNTS RECEIVABLE (Tables)
ACCOUNTS RECEIVABLE (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Receivables [Abstract] | |
Accounts Receivable | The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2019 December 31, 2018 Customer (1) $ 85 $ 99 Customer, Unbilled 59 45 Due from Affiliates (Note 5) 6 8 Other 14 25 Allowance for Doubtful Accounts (5 ) (5 ) Accounts Receivable, Net $ 159 $ 172 (1) Includes $3 million as of June 30, 2019 , and $8 million as of December 31, 2018 , of receivables related to revenue from derivative instruments. |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Balances and Transactions | The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) June 30, 2019 December 31, 2018 Receivables from Related Parties UNS Electric $ 4 $ 7 UNS Gas 2 1 Total Due from Related Parties $ 6 $ 8 Payables to Related Parties SES $ 2 $ 2 UNS Energy 2 1 UNS Electric — 1 UNS Gas — 1 Total Due to Related Parties $ 4 $ 5 The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 2 $ 1 $ 3 $ 3 Control Area Services, UNS Electric (2) 1 1 2 1 Common Costs, UNS Energy Affiliates (3) 5 5 10 9 Goods and Services Provided by Affiliates to TEP Supplemental Workforce, SES (4) 4 4 7 7 Corporate Services, UNS Energy (5) 2 1 3 3 Corporate Services, UNS Energy Affiliates (6) 1 1 2 3 (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable Open Access Transmission Tariff. (2) TEP charges UNS Electric for control area services under a FERC-approved Control Area Services Agreement. (3) Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. (4) SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management. (5) Costs for corporate services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 83% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were $1 million and $3 million for the three and six months ended June 30, 2019 and 2018 , respectively. (6) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. |
LEASES (Tables)
LEASES (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Leases [Abstract] | |
Assets And Liabilities, Lessee | TEP’s leases are included on the balance sheet as follows: (in millions) Lease Type June 30, 2019 Lease Assets Utility Plant Under Finance Leases Finance $ 249 Accumulated Amortization of Finance Lease Assets Finance (80 ) Regulatory and Other Assets, Other Operating 8 Lease Liabilities Current Liabilities, Finance Lease Obligations (1)(2) Finance 175 Finance Lease Obligations (2) Finance 6 Current Liabilities, Other Operating 1 Regulatory and Other Liabilities, Other Operating 7 (1) TEP recorded the fair value purchase price of Gila River Unit 2 as determined by SRP's 2018 purchase price. TEP expects to complete the purchase of Gila River Unit 2 in December 2019. (2) Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021. TEP may renew the two leases or exercise its remaining fixed-price purchase options. |
Lease, Cost | The following table presents TEP's non-cash investing information related to its leases: Six Months Ended (in millions) June 30, 2018 Assets Obtained in Exchange for New Lease Liabilities Capital Leases $ 165 The following table presents the components of TEP’s lease cost: Three Months Ended Six Months Ended (in millions) June 30, 2019 Finance Amortization of Leased Assets $ 3 $ 6 Interest on Lease Liabilities (1) 3 6 Operating — 1 Variable 5 9 Total Lease Cost $ 11 $ 22 (1) Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income. The following table presents TEP's cash flow information related to its leases: Six Months Ended (in millions) June 30, 2019 Cash Paid for Amounts Included in the Measurement of Lease Liabilities Operating Cash Flows used for Finance Leases $ 7 Financing Cash Flows used for Finance Leases 11 Right-of-Use Assets Obtained in Exchange for New Lease Liabilities Operating Leases 8 |
Lessee, Operating Lease, Liability, Maturity | As of June 30, 2019 , TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: (in millions) Finance Leases (1) Operating Leases Total 2019 $ 170 $ 1 $ 171 2020 20 1 21 2021 — 1 1 2022 — 1 1 2023 — 1 1 Thereafter — 5 5 Total Lease Payments 190 10 200 Less Imputed Interest 9 2 11 Total Lease Obligations 181 8 189 Less Current Portion 175 1 176 Total Non-Current Lease Obligations $ 6 $ 7 $ 13 (1) Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20 -month lease term. |
Finance Lease, Liability, Maturity | As of June 30, 2019 , TEP had the following future minimum lease payments, excluding payments to lessors for variable costs: (in millions) Finance Leases (1) Operating Leases Total 2019 $ 170 $ 1 $ 171 2020 20 1 21 2021 — 1 1 2022 — 1 1 2023 — 1 1 Thereafter — 5 5 Total Lease Payments 190 10 200 Less Imputed Interest 9 2 11 Total Lease Obligations 181 8 189 Less Current Portion 175 1 176 Total Non-Current Lease Obligations $ 6 $ 7 $ 13 (1) Includes monthly demand charge payments to SRP through February 2020 related to Gila River Unit 2's estimated 20 -month lease term. |
Schedule of Lease Term and Discount Rate | The following table presents TEP's lease terms and discount rate related to its leases: June 30, 2019 Weighted-Average Remaining Lease Term (years) Finance Leases 1 Operating Leases 12 Weighted-Average Discount Rate Finance Leases 7.1 % Operating Leases 4.1 % |
Schedule of Future Minimum Rental Payments for Operating Leases | As of December 31, 2018 , future minimum lease payments were as follows: (in millions) Capital Leases Operating Leases 2019 $ 187 $ 1 2020 20 1 2021 — 1 2022 — 1 2023 — 1 Thereafter — 5 Total Lease Payments 207 $ 10 Less: Imputed Interest 14 Total Lease Obligations 193 Less: Current Portion 173 Total Non-Current Lease Obligations $ 20 |
Schedule of Future Minimum Lease Payments for Capital Leases | As of December 31, 2018 , future minimum lease payments were as follows: (in millions) Capital Leases Operating Leases 2019 $ 187 $ 1 2020 20 1 2021 — 1 2022 — 1 2023 — 1 Thereafter — 5 Total Lease Payments 207 $ 10 Less: Imputed Interest 14 Total Lease Obligations 193 Less: Current Portion 173 Total Non-Current Lease Obligations $ 20 |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Retirement Benefits [Abstract] | |
Components of Net Periodic Benefit Cost | Net periodic benefit cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended June 30, (in millions) 2019 2018 2019 2018 Service Cost $ 3 $ 3 $ 1 $ 1 Non-Service Cost (1) Interest Cost 5 4 1 1 Expected Return on Plan Assets (7 ) (7 ) — — Amortization of Net Loss 2 2 — — Net Periodic Benefit Cost $ 3 $ 2 $ 2 $ 2 Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Service Cost $ 6 $ 7 $ 2 $ 2 Non-Service Cost (1) Interest Cost 9 8 1 1 Expected Return on Plan Assets (13 ) (14 ) — — Amortization of Net Loss 4 4 — — Net Periodic Benefit Cost $ 6 $ 5 $ 3 $ 3 (1) The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income. |
FAIR VALUE MEASUREMENTS AND D_2
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables) | 6 Months Ended |
Jun. 30, 2019 | |
Fair Value Disclosures [Abstract] | |
Financial Instruments Measured at Fair Value on Recurring Basis | The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis classified in their entirety based on the lowest level of input that is significant to the fair value measurement: Level 1 Level 2 Level 3 Total (in millions) June 30, 2019 Assets Cash Equivalents (1) $ 67 $ — $ — $ 67 Restricted Cash (1) 14 — — 14 Energy Derivative Contracts, Regulatory Recovery (2) — 10 3 13 Energy Derivative Contracts, No Regulatory Recovery (2) — — 6 6 Total Assets 81 10 9 100 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (48 ) (13 ) (61 ) Total Liabilities — (48 ) (13 ) (61 ) Total Assets (Liabilities), Net $ 81 $ (38 ) $ (4 ) $ 39 (in millions) December 31, 2018 Assets Cash Equivalents (1) $ 125 $ — $ — $ 125 Restricted Cash (1) 15 — — 15 Energy Derivative Contracts, Regulatory Recovery (2) — 10 — 10 Energy Derivative Contracts, No Regulatory Recovery (2) — — 2 2 Total Assets 140 10 2 152 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (35 ) (2 ) (37 ) Total Liabilities — (35 ) (2 ) (37 ) Total Assets (Liabilities), Net $ 140 $ (25 ) $ — $ 115 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds, certificates of deposit, and insured cash sweep accounts valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets. (2) Energy Derivative Contracts include gas swap agreements (Level 2) and forward purchased power and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. In 2019, Derivative Contract Liabilities increased primarily due to increases in volume and decreases in forward market prices of natural gas. |
Potential Offset of Assets by Counterparty Netting and Cash Collateral | All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral. Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) June 30, 2019 Derivative Assets Energy Derivative Contracts $ 19 $ 13 $ — $ 6 Derivative Liabilities Energy Derivative Contracts (61 ) (13 ) — (48 ) (in millions) December 31, 2018 Derivative Assets Energy Derivative Contracts $ 12 $ 11 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (37 ) (11 ) — (26 ) |
Potential Offset of Liabilities by Counterparty Netting and Cash Collateral | All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral. Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) June 30, 2019 Derivative Assets Energy Derivative Contracts $ 19 $ 13 $ — $ 6 Derivative Liabilities Energy Derivative Contracts (61 ) (13 ) — (48 ) (in millions) December 31, 2018 Derivative Assets Energy Derivative Contracts $ 12 $ 11 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (37 ) (11 ) — (26 ) |
Financial Impact of Energy Contracts | The table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Operating Revenues $ 5 $ 4 $ 5 $ 5 Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Unrealized Net Gain (Loss) $ (11 ) $ (14 ) $ (20 ) $ (32 ) |
Derivative Volumes | The following table presents volumes associated with the energy contracts: June 30, 2019 December 31, 2018 Power Contracts GWh 5,836 1,743 Gas Contracts BBtu 138,837 146,933 |
Fair Value Inputs, Assets, Quantitative Information Regarding Unobservable Inputs | The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Approach Fair Value of Unobservable Inputs Range of Unobservable Inputs Assets Liabilities (in millions) June 30, 2019 Forward Power Contracts Market approach $ 9 $ (13 ) Market price per MWh $ 17.05 $ 64.60 (in millions) December 31, 2018 Forward Power Contracts Market approach $ 3 $ (2 ) Market price per MWh $ 16.80 $ 47.05 |
Level 3 Fair Value Reconciliation of Changes | The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period: Three Months Ended June 30, Six Months Ended June 30, (in millions) 2019 2018 2019 2018 Beginning of Period $ (6 ) $ 1 $ 1 $ 2 Gains (Losses) Recorded Regulatory Assets or Liabilities, Derivative Instruments (2 ) — (10 ) — Operating Revenues 5 4 5 4 Settlements (1 ) — — (1 ) End of Period $ (4 ) $ 5 $ (4 ) $ 5 Gains (Losses), Assets (Liabilities) Still Held $ 3 $ 6 $ (4 ) $ 5 |
Face Value and Estimated Fair Value of Long-Term Debt | The following table includes the face value and estimated fair value of TEP's long-term debt: Fair Value Hierarchy Face Value Fair Value (in millions) June 30, 2019 December 31, 2018 June 30, 2019 December 31, 2018 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,629 $ 1,629 $ 1,745 $ 1,672 |
NATURE OF OPERATIONS AND FINA_4
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Nature of Operations) (Details) customer in Thousands | 6 Months Ended |
Jun. 30, 2019mi²customer | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of retail customers | customer | 427 |
Area in which company generates transmits and distributes electricity to retail electric customers (square mile) | mi² | 1,155 |
NATURE OF OPERATIONS AND FINA_5
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Cash and Cash Equivalents) (Details) - USD ($) $ in Thousands | Jun. 30, 2019 | Dec. 31, 2018 | Jun. 30, 2018 | Dec. 31, 2017 |
Cash and Cash Equivalents [Line Items] | ||||
Cash and Cash Equivalents | $ 69,692 | $ 138,114 | $ 6,000 | |
Total Cash, Cash Equivalents, and Restricted Cash | 83,873 | $ 152,747 | 16,470 | $ 49,501 |
Investments and Other Property | ||||
Cash and Cash Equivalents [Line Items] | ||||
Restricted Cash | 13,000 | 9,000 | ||
Current Assets—Other | ||||
Cash and Cash Equivalents [Line Items] | ||||
Restricted Cash | $ 1,000 | $ 1,000 |
REGULATORY MATTERS (2019 ACC Ra
REGULATORY MATTERS (2019 ACC Rate Case) (Details) - Arizona Corporation Commission $ in Millions | Apr. 01, 2019USD ($) |
Non-fuel Component of Base Rate | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | $ 115 |
Original cost rate base (percentage) | 7.68% |
Original cost rate base | $ 2,700 |
Original cost of equity (percentage) | 10.35% |
Average original cost of debt (percentage) | 4.65% |
Fuel Component of Base Rate | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | $ (39) |
Revenue Component of Base Rate | |
Public Utilities, General Disclosures [Line Items] | |
Non-fuel base rate increase (decrease) | $ 76 |
Non-fuel base rate increase (percentage) | 7.80% |
REGULATORY MATTERS (2019 FERC R
REGULATORY MATTERS (2019 FERC Rate Case) (Details) - USD ($) $ in Millions | May 31, 2019 | Jun. 30, 2019 | Dec. 31, 2018 |
Public Utilities, General Disclosures [Line Items] | |||
Regulatory assets | $ 411 | $ 400 | |
FERC | Transmission Services Rate | |||
Public Utilities, General Disclosures [Line Items] | |||
Return on equity (percentage) | 10.40% | ||
Requested recovery in development, percentage | 100.00% | ||
Requested recovery in development | $ 9 | ||
Regulatory assets | $ 4 |
REGULATORY MATTERS (Federal Tax
REGULATORY MATTERS (Federal Tax Legislation) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | |
Regulatory Assets [Roll Forward] | ||||||
Regulatory Deferral | $ 3,156 | $ 0 | ||||
Arizona Corporation Commission | ||||||
Public Utilities, General Disclosures [Line Items] | ||||||
Change in tax rate, refund to customers, net of amortization | $ 33,000 | |||||
Arizona Corporation Commission | Revenue Refund | ||||||
Regulatory Assets [Roll Forward] | ||||||
Beginning of Period | $ 3,000 | $ (7,000) | 4,000 | 0 | $ 4,000 | 0 |
ACC Refund (Reduction in Operating Revenues) | (9,000) | (10,000) | (16,000) | (17,000) | ||
Amount Returned to Customers through Bill Credits | 6,000 | 12,000 | 10,000 | 12,000 | ||
Regulatory Deferral | 1,000 | 0 | 3,000 | 0 | ||
End of Period | $ 1,000 | $ (5,000) | $ 1,000 | $ (5,000) | $ 4,000 | |
Arizona Corporation Commission | Scenario, Forecast | ||||||
Regulatory Assets [Roll Forward] | ||||||
Amount Returned to Customers through Bill Credits | $ 34,000 |
REGULATORY MATTERS (Cost Recove
REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
Feb. 28, 2019 | Jan. 31, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Dec. 31, 2025 | Dec. 31, 2019 | |
Purchased Power and Fuel Adjustment Clause | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Beginning of Period | $ (9) | $ (22) | $ (4) | $ (17) | $ (9) | $ (17) | ||
Deferred Fuel and Purchased Power Costs | 6 | (11) | 3 | (9) | ||||
PPFAC Refunds (Recoveries) | 7 | (3) | 5 | 0 | ||||
End of Period | (9) | (18) | $ (9) | (18) | ||||
Purchased Power and Fuel Adjustment Clause | ||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||
Months approved rate in effect unless modified | 12 months | |||||||
Renewable Energy Standard | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Approved spending budget | $ 54 | |||||||
Renewable Energy Standard | Scenario, Forecast | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Renewable energy target percentage | 15.00% | 9.00% | ||||||
Distributed generation requirement percent of target percentage (percentage) | 30.00% | |||||||
Demand Side Management | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Recovery revenue | $ 2 | 2 | ||||||
Energy Efficiency Standards | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Approved recovery of spending budget | $ 23 | |||||||
Lost Fixed Cost Recovery | ||||||||
Regulatory Liabilities [Roll Forward] | ||||||||
Recovery revenue | $ 6 | $ 5 | $ 16 | $ 13 | ||||
Cap on increase in lost fixed cost recovery rate (percentage) | 2.00% |
REGULATORY MATTERS (Regulatory
REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2019 | Dec. 31, 2018 | |
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 411,000 | $ 400,000 |
Less Current Portion | 118,699 | 106,725 |
Total Non-Current Regulatory Assets | 292,068 | 293,078 |
Pension and Other Postretirement Benefits | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | 123,000 | 126,000 |
Early Generation Retirement Costs | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 67,000 | 72,000 |
Derivatives | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 11 years | |
Total Regulatory Assets | $ 47,000 | 27,000 |
Income Taxes Recoverable through Future Rates | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 44,000 | 47,000 |
Lost Fixed Cost Recovery | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 2 years | |
Total Regulatory Assets | $ 42,000 | 35,000 |
Final Mine Reclamation and Retiree Healthcare Costs | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 19 years | |
Total Regulatory Assets | $ 26,000 | 29,000 |
Property Tax Deferrals | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Assets | $ 24,000 | 23,000 |
Springerville Unit 1 Leasehold Improvements | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 4 years | |
Total Regulatory Assets | $ 10,000 | 11,000 |
Other Regulatory Assets | ||
Regulatory Assets [Line Items] | ||
Total Regulatory Assets | $ 28,000 | $ 30,000 |
REGULATORY MATTERS (Regulator_2
REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2019 | Dec. 31, 2018 | |
Regulatory Liabilities [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Liabilities | $ 588,000 | $ 607,000 |
Less Current Portion | 89,898 | 95,094 |
Total Non-Current Regulatory Liabilities | 497,572 | 512,425 |
Income Taxes Payable through Future Rates | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 344,000 | 354,000 |
Net Cost of Removal | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 162,000 | 171,000 |
Renewable Energy Standard | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 53,000 | 52,000 |
Purchased Power and Fuel Adjustment Clause | ||
Regulatory Liabilities [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Total Regulatory Liabilities | $ 9,000 | 17,000 |
Deferred Investment Tax Credits | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | 7,000 | 7,000 |
Other Regulatory Liabilities | ||
Regulatory Liabilities [Line Items] | ||
Total Regulatory Liabilities | $ 13,000 | $ 6,000 |
REGULATORY MATTERS (Regulator_3
REGULATORY MATTERS (Regulatory Assets and Liabilities - Footnotes) (Details) | 6 Months Ended |
Jun. 30, 2019 | |
Regulatory Assets [Line Items] | |
Remaining Recovery Period (years) | 1 year |
Navajo and Sundt Units 1 and 2 | |
Regulatory Assets [Line Items] | |
Useful life (in years) | 10 years |
Springerville Unit 1 Leasehold Improvements | |
Regulatory Assets [Line Items] | |
Useful life (in years) | 10 years |
Remaining Recovery Period (years) | 4 years |
REVENUE (Details)
REVENUE (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Disaggregation of Revenue [Line Items] | ||||
Revenues from Contracts with Customers | $ 309,000 | $ 335,000 | $ 619,000 | $ 588,000 |
Alternative Revenues | 6,000 | 5,000 | 18,000 | 15,000 |
Other | 11,000 | 14,000 | 22,000 | 26,000 |
Total Operating Revenues | 326,091 | 354,246 | 659,094 | 629,336 |
Retail | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from Contracts with Customers | 236,000 | 273,000 | 438,000 | 465,000 |
Wholesale | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from Contracts with Customers | 43,000 | 35,000 | 127,000 | 73,000 |
Other Services | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from Contracts with Customers | $ 30,000 | $ 27,000 | $ 54,000 | $ 50,000 |
ACCOUNTS RECEIVABLE (Details)
ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands | Jun. 30, 2019 | Dec. 31, 2018 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for Doubtful Accounts | $ (5,000) | $ (5,000) |
Accounts Receivable, Net | 159,165 | 172,367 |
Customer | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable, gross | 85,000 | 99,000 |
Customer | Derivatives | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable, gross | 3,000 | 8,000 |
Customer | Due from Affiliates | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable, gross | 6,000 | 8,000 |
Customer | Customer, Unbilled | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable, gross | 59,000 | 45,000 |
Other | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable, gross | $ 14,000 | $ 25,000 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Thousands | Jul. 30, 2019 | Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | Jul. 22, 2019 | Dec. 31, 2018 |
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Due from related parties | $ 6,000 | $ 6,000 | $ 8,000 | ||||
Due to related parties | 4,000 | 4,000 | 5,000 | ||||
Supplemental workforce | 103,962 | $ 118,540 | 244,360 | $ 208,752 | |||
Transmission Revenues, UNS Electric | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Revenue from related party | 2,000 | 1,000 | 3,000 | 3,000 | |||
Control Area Services, UNS Electric | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Control area services | 1,000 | 1,000 | 2,000 | 1,000 | |||
Common Costs, UNS Energy Affiliates | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Common costs | 5,000 | 5,000 | 10,000 | 9,000 | |||
Supplemental Workforce, SES | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Supplemental workforce | 4,000 | 4,000 | 7,000 | 7,000 | |||
Corporate Services, UNS Energy | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Corporate services | 2,000 | 1,000 | $ 3,000 | 3,000 | |||
Massachusetts Formula - TEP's allocation (percentage) | 83.00% | ||||||
Management fee | 1,000 | 1,000 | $ 3,000 | 3,000 | |||
Corporate Services, UNS Energy Affiliates | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Corporate services | 1,000 | $ 1,000 | 2,000 | $ 3,000 | |||
UNS Electric | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Due from related parties | 4,000 | 4,000 | 7,000 | ||||
Due to related parties | 0 | 0 | 1,000 | ||||
UNS Gas | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Due from related parties | 2,000 | 2,000 | 1,000 | ||||
Due to related parties | 0 | 0 | 1,000 | ||||
Uns Energy | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Due to related parties | 2,000 | 2,000 | 1,000 | ||||
SES | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Due to related parties | $ 2,000 | $ 2,000 | $ 2,000 | ||||
Subsequent Event | Uns Energy | |||||||
Related Party Transaction, Due to/from Related Party [Abstract] | |||||||
Dividends declared | $ 38,000 | ||||||
Dividends paid | $ 38,000 |
LEASES (Narrative) (Details)
LEASES (Narrative) (Details) $ in Millions | 1 Months Ended | 6 Months Ended |
May 31, 2018 | Jun. 30, 2019USD ($)option | |
Lessee, Lease, Description [Line Items] | ||
Renewal term | 15 years | |
Lessor, Operating Lease, Payments, Fiscal Year Maturity | ||
Remainder of 2019 | $ 1 | |
2020 | 1 | |
2021 | 1 | |
2022 | 1 | |
2023 | 1 | |
Thereafter | $ 1 | |
Energy Storage | ||
Lessee, Lease, Description [Line Items] | ||
Lease not yet commenced, term of contract | 20 years | |
Office Facility and Utility Property | ||
Lessee, Lease, Description [Line Items] | ||
Number of renewal options | option | 1 | |
Tolling PPA | ||
Lessee, Lease, Description [Line Items] | ||
Option to purchase the unit | 3 years | |
Term of contract | 20 years | |
Minimum | Office Facility and Utility Property | ||
Lessee, Lease, Description [Line Items] | ||
Remaining lease term | 3 years | |
Renewal term | 2 years | |
Maximum | ||
Lessee, Lease, Description [Line Items] | ||
Remaining lease term | 22 years | |
Maximum | Office Facility and Utility Property | ||
Lessee, Lease, Description [Line Items] | ||
Remaining lease term | 5 years | |
Renewal term | 10 years |
LEASES (Assets and Liabilities)
LEASES (Assets and Liabilities) (Details) $ in Thousands | 6 Months Ended | |
Jun. 30, 2019USD ($)contract | Dec. 31, 2018USD ($) | |
Leases [Abstract] | ||
Utility Plant Under Finance Leases | $ 248,635 | $ 248,635 |
Accumulated Amortization of Finance Lease Assets | (79,829) | (73,646) |
Regulatory and Other Assets, Other | 8,000 | |
Current Liabilities, Finance Lease Obligations | 175,202 | 172,510 |
Finance Lease Obligations | 6,192 | $ 19,773 |
Current Liabilities, Other | 1,000 | |
Regulatory and Other Liabilities, Other | $ 7,000 | |
Number of contracts | contract | 2 |
LEASES (Lease Cost) (Details)
LEASES (Lease Cost) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended |
Jun. 30, 2019 | Jun. 30, 2019 | |
Finance | ||
Amortization of Leased Assets | $ 3 | $ 6 |
Interest on Lease Liabilities | 3 | 6 |
Operating | 0 | 1 |
Variable | 5 | 9 |
Total Lease Cost | $ 11 | $ 22 |
LEASES (Lease Liability) (Detai
LEASES (Lease Liability) (Details) $ in Millions | Jun. 30, 2019USD ($) |
Finance Leases | |
2019 | $ 170 |
2020 | 20 |
2021 | 0 |
2022 | 0 |
2023 | 0 |
Thereafter | 0 |
Total Lease Payments | 190 |
Less Imputed Interest | 9 |
Total Lease Obligations | 181 |
Less Current Portion | 175 |
Total Non-Current Lease Obligations | 6 |
Operating Leases | |
2019 | 1 |
2020 | 1 |
2021 | 1 |
2022 | 1 |
2023 | 1 |
Thereafter | 5 |
Total Lease Payments | 10 |
Less Imputed Interest | 2 |
Total Lease Obligations | 8 |
Less Current Portion | 1 |
Total Non-Current Lease Obligations | 7 |
Total | |
2019 | 171 |
2020 | 21 |
2021 | 1 |
2022 | 1 |
2023 | 1 |
Thereafter | 5 |
Total Lease Payments | 200 |
Less Imputed Interest | 11 |
Total Lease Obligations | 189 |
Less Current Portion | 176 |
Total Non-Current Lease Obligations | $ 13 |
GIla River Unit 2 | |
Lessee, Lease, Description [Line Items] | |
Term of contract | 20 months |
LEASES (Term and Rate) (Details
LEASES (Term and Rate) (Details) | Jun. 30, 2019 |
Leases [Abstract] | |
Weighted-Average Remaining Lease Term (years), Finance Lease | 1 year |
Weighted-Average Remaining Lease Term (years), Operating Lease | 12 years |
Weighted-Average Discount Rate, Finance Lease | 7.10% |
Weighted-Average Discount Rate, Operating Lease | 4.10% |
LEASES (Cash Flows) (Details)
LEASES (Cash Flows) (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2019USD ($) | |
Leases [Abstract] | |
Operating Cash Flows used for Finance Leases | $ 7 |
Financing Cash Flows used for Finance Leases | 11 |
Right-of-Use Assets Obtained in Exchange for New Lease Liabilities, Operating Lease | $ 8 |
LEASES (Future Minimum Lease Pa
LEASES (Future Minimum Lease Payments) (Details) - USD ($) $ in Thousands | Jun. 30, 2019 | Dec. 31, 2018 |
Capital Leases | ||
2019 | $ 187,000 | |
2020 | 20,000 | |
2021 | 0 | |
2022 | 0 | |
2023 | 0 | |
Thereafter | 0 | |
Capital Leases, Future Minimum Payments Due | 207,000 | |
Less: Imputed Interest | 14,000 | |
Total Lease Obligations | 193,000 | |
Less: Current Portion | $ 175,202 | 172,510 |
Total Non-Current Lease Obligations | $ 6,192 | 19,773 |
Operating Leases | ||
2019 | 1,000 | |
2020 | 1,000 | |
2021 | 1,000 | |
2022 | 1,000 | |
2023 | 1,000 | |
Thereafter | 5,000 | |
Total Lease Payments | $ 10,000 |
LEASES (Non-cash Investing Info
LEASES (Non-cash Investing Information) (Details) $ in Millions | 6 Months Ended |
Jun. 30, 2018USD ($) | |
Leases [Abstract] | |
Capital Leases | $ 165 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Commitments) (Details) $ in Millions | Mar. 31, 2019USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
Contractual obligation | $ 370 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES (Contingencies) (Details) - Navajo, San Juan, Four Corners $ in Millions | 6 Months Ended | |
Jun. 30, 2019USD ($)mine | Dec. 31, 2018USD ($) | |
Commitments And Contingencies [Line Items] | ||
Number of mines expected to be reclaimed | mine | 3 | |
Share of reclamation costs anticipated | $ 63 | |
Other Liabilities | ||
Commitments And Contingencies [Line Items] | ||
Environmental exit costs, costs accrued to date | $ 36 | $ 36 |
COMMITMENTS AND CONTINGENCIES_3
COMMITMENTS AND CONTINGENCIES (Performance guarantees) (Details) - Performance Guarantee | Jun. 30, 2019USD ($) |
Guarantor Obligations [Line Items] | |
Guarantor obligations, current carrying value | $ 0 |
Navajo, San Juan, Luna | |
Guarantor Obligations [Line Items] | |
Guarantor obligations, maximum exposure, undiscounted | 0 |
Four Corner | |
Guarantor Obligations [Line Items] | |
Guarantor obligations, maximum exposure, undiscounted | $ 250,000,000 |
EMPLOYEE BENEFIT PLANS (Details
EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Pension Benefits | ||||
Components of Net Periodic Benefit Plan Cost | ||||
Service Cost | $ 3 | $ 3 | $ 6 | $ 7 |
Interest Cost | 5 | 4 | 9 | 8 |
Expected Return on Plan Assets | (7) | (7) | (13) | (14) |
Amortization of Net Loss | 2 | 2 | 4 | 4 |
Net Periodic Benefit Cost | 3 | 2 | 6 | 5 |
Other Postretirement Benefits | ||||
Components of Net Periodic Benefit Plan Cost | ||||
Service Cost | 1 | 1 | 2 | 2 |
Interest Cost | 1 | 1 | 1 | 1 |
Expected Return on Plan Assets | 0 | 0 | 0 | 0 |
Amortization of Net Loss | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost | $ 2 | $ 2 | $ 3 | $ 3 |
FAIR VALUE MEASUREMENTS AND D_3
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Recurring - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Assets | ||
Cash Equivalents | $ 67 | $ 125 |
Restricted Cash | 14 | 15 |
Energy Derivative Contract Assets - Regulatory Recovery | 13 | 10 |
Energy Derivative Contract Assets - No Regulatory Recovery | 6 | 2 |
Total Assets | 100 | 152 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | (61) | (37) |
Total Liabilities | (61) | (37) |
Total Assets (Liabilities), Net | 39 | 115 |
Level 1 | ||
Assets | ||
Cash Equivalents | 67 | 125 |
Restricted Cash | 14 | 15 |
Energy Derivative Contract Assets - Regulatory Recovery | 0 | 0 |
Energy Derivative Contract Assets - No Regulatory Recovery | 0 | 0 |
Total Assets | 81 | 140 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | 0 | 0 |
Total Liabilities | 0 | 0 |
Total Assets (Liabilities), Net | 81 | 140 |
Level 2 | ||
Assets | ||
Cash Equivalents | 0 | 0 |
Restricted Cash | 0 | 0 |
Energy Derivative Contract Assets - Regulatory Recovery | 10 | 10 |
Energy Derivative Contract Assets - No Regulatory Recovery | 0 | 0 |
Total Assets | 10 | 10 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | (48) | (35) |
Total Liabilities | (48) | (35) |
Total Assets (Liabilities), Net | (38) | (25) |
Level 3 | ||
Assets | ||
Cash Equivalents | 0 | 0 |
Restricted Cash | 0 | 0 |
Energy Derivative Contract Assets - Regulatory Recovery | 3 | 0 |
Energy Derivative Contract Assets - No Regulatory Recovery | 6 | 2 |
Total Assets | 9 | 2 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | (13) | (2) |
Total Liabilities | (13) | (2) |
Total Assets (Liabilities), Net | $ (4) | $ 0 |
FAIR VALUE MEASUREMENTS AND D_4
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - Energy Derivative Contracts - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Derivative Assets | ||
Gross Amount Recognized in the Balance Sheets | $ 19 | $ 12 |
Counterparty Netting of Energy Contracts | 13 | 11 |
Cash Collateral Received/Posted | 0 | 0 |
Net Amount | 6 | 1 |
Derivative Liabilities | ||
Gross Amount Recognized in the Balance Sheets | (61) | (37) |
Counterparty Netting of Energy Contracts | (13) | (11) |
Cash Collateral Received/Posted | 0 | 0 |
Net Amount | $ (48) | $ (26) |
FAIR VALUE MEASUREMENTS AND D_5
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) $ in Millions | Jun. 30, 2019USD ($) |
Interest Rate Swap | |
Derivative [Line Items] | |
Derivative liability, notional amount | $ 6 |
FAIR VALUE MEASUREMENTS AND D_6
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Percent of long-term trading contract gains shared with ratepayers (percentage) | 10.00% | |||
Operating Revenues | $ 326,091 | $ 354,246 | $ 659,094 | $ 629,336 |
Energy Derivative Contracts | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized Net Gain (Loss) | (11,000) | (14,000) | (20,000) | (32,000) |
Operating Revenues | $ 5,000 | $ 4,000 | $ 5,000 | $ 5,000 |
FAIR VALUE MEASUREMENTS AND D_7
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) | Jun. 30, 2019GWhBTU | Dec. 31, 2018GWhBTU |
Power Contracts GWh | ||
Derivative Volume [Line Items] | ||
Derivatives volumes | GWh | 5,836 | 1,743 |
Gas Contracts BBtu | ||
Derivative Volume [Line Items] | ||
Derivatives volumes | BTU | 138,837,000,000,000 | 146,933,000,000,000 |
FAIR VALUE MEASUREMENTS AND D_8
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Details) - Level 3 - Forward Power Contracts $ in Millions | Jun. 30, 2019USD ($)$ / megawatt_hour | Dec. 31, 2018USD ($)$ / megawatt_hour |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Derivative assets | $ | $ 9 | $ 3 |
Derivative liabilities | $ | $ (13) | $ (2) |
Minimum | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Market price per MWh (usd per MWh) | $ / megawatt_hour | 17.05 | 16.80 |
Maximum | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Market price per MWh (usd per MWh) | $ / megawatt_hour | 64.60 | 47.05 |
FAIR VALUE MEASUREMENTS AND D_9
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Reconciliation of Changes in Fair Value of Assets and Liabilities) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2019 | Jun. 30, 2018 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||||
Beginning of Period | $ (6) | $ 1 | $ 1 | $ 2 |
Gains (Losses) Recorded | ||||
Regulatory Assets or Liabilities, Derivative Instruments | (2) | 0 | (10) | 0 |
Operating Revenues | 5 | 4 | 5 | 4 |
Settlements | (1) | 0 | 0 | (1) |
End of Period | (4) | 5 | (4) | 5 |
Gains (Losses), Assets (Liabilities) Still Held | $ 3 | $ 6 | $ (4) | $ 5 |
FAIR VALUE MEASUREMENTS AND _10
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($) | Jun. 30, 2019 | Dec. 31, 2018 |
Derivative [Line Items] | ||
FV of derivative instruments in net liability position with credit risk related features, including normal purchase normal sale | $ 84,000,000 | $ 41,000,000 |
Collateral posted | 0 | |
Additional collateral required to post if credit-risk contingent features are triggered | 84,000,000 | |
Amount relating to outstanding net payable balances for settled positions | ||
Derivative [Line Items] | ||
Additional collateral required to post if credit-risk contingent features are triggered | $ 15,000,000 |
FAIR VALUE MEASUREMENTS AND _11
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - Level 2 - USD ($) $ in Millions | Jun. 30, 2019 | Dec. 31, 2018 |
Face Value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-Term Debt, including Current Maturities, Face Value | $ 1,629 | $ 1,629 |
Fair Value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Long-Term Debt, including Current Maturities, Fair Value | $ 1,745 | $ 1,672 |