Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 14, 2018 | Jun. 30, 2017 | |
Document Documentand Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | TUCSON ELECTRIC POWER COMPANY | ||
Entity Central Index Key | 100,122 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filer | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 32,139,434 | ||
Entity Public Float | $ 0 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating Revenues | |||
Retail | $ 1,040,682 | $ 989,580 | $ 1,021,543 |
Wholesale | 174,742 | 117,341 | 167,020 |
Other | 125,511 | 128,074 | 117,981 |
Total Operating Revenues | 1,340,935 | 1,234,995 | 1,306,544 |
Operating Expenses | |||
Fuel | 285,551 | 289,862 | 305,559 |
Purchased Power | 136,425 | 85,354 | 124,764 |
Transmission and Other PPFAC Recoverable Costs | 36,239 | 23,781 | 24,798 |
Increase (Decrease) to Reflect PPFAC Recovery Treatment | (32,660) | 21,064 | 39,787 |
Total Fuel and Purchased Power | 425,555 | 420,061 | 494,908 |
Operations and Maintenance | 360,302 | 353,905 | 345,356 |
Depreciation | 152,874 | 146,097 | 138,093 |
Amortization | 22,255 | 22,498 | 19,261 |
Taxes Other Than Income Taxes | 53,623 | 49,303 | 49,623 |
Total Operating Expenses | 1,014,609 | 991,864 | 1,047,241 |
Operating Income | 326,326 | 243,131 | 259,303 |
Other Income (Deductions) | |||
Interest Income | 742 | 111 | 93 |
Other Income | 14,128 | 5,636 | 6,647 |
Other Expense | (3,344) | (3,019) | (2,833) |
Appreciation (Depreciation) in Value of Investments | 2,791 | 2,147 | (142) |
Total Other Income (Deductions) | 14,317 | 4,875 | 3,765 |
Interest Expense | |||
Long-Term Debt | 62,018 | 62,015 | 61,159 |
Capital Leases | 2,554 | 3,356 | 3,994 |
Other Interest Expense | 718 | 531 | 1,134 |
Interest Capitalized | (2,078) | (1,710) | (2,732) |
Total Interest Expense | 63,212 | 64,192 | 63,555 |
Income Before Income Taxes | 277,431 | 183,814 | 199,513 |
Income Tax Expense | 100,763 | 59,376 | 71,719 |
Net Income | $ 176,668 | $ 124,438 | $ 127,794 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |||
Net Income | $ 176,668 | $ 124,438 | $ 127,794 |
Other Comprehensive Income | |||
Net of Income Tax (Expense) Benefit of $(305), $(420), and $(821) | 485 | 652 | 1,261 |
Supplemental Executive Retirement Plan Adjustments: | (2,156) | (643) | 101 |
Total Other Comprehensive Income, Net of Tax | (1,671) | 9 | 1,362 |
Total Comprehensive Income | $ 174,997 | $ 124,447 | $ 129,156 |
CONSOLIDATED STATEMENTS OF COM4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |||
Income Tax on Net Changes in Fair Value of Cash Flow Hedges | $ (305) | $ (420) | $ (821) |
Income Tax on Supplemental Executive Retirement Plan Adjustments | $ 637 | $ 399 | $ (63) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Cash Flows [Abstract] | |||
Net Income | $ 176,668 | $ 124,438 | $ 127,794 |
Adjustments to Reconcile Net Income To Net Cash Flows from Operating Activities: | |||
Depreciation Expense | 152,874 | 146,097 | 138,093 |
Amortization Expense | 22,255 | 22,498 | 19,261 |
Amortization of Debt Issuance Costs | 2,349 | 2,853 | 3,043 |
Use of Renewable Energy Credits for Compliance | 25,453 | 17,618 | 19,731 |
Deferred Income Taxes | 100,762 | 59,367 | 72,026 |
Pension and Other Postretirement Benefits Expense | 16,039 | 15,338 | 18,588 |
Pension and Other Postretirement Benefits Funding | (14,430) | (13,459) | (30,682) |
Allowance for Equity Funds Used During Construction | (5,322) | (4,522) | (5,352) |
FERC Transmission Refund Payable | (4,878) | 4,878 | 0 |
Changes in Current Assets and Current Liabilities: | |||
Accounts Receivable | (13,219) | 7,809 | (3,019) |
Materials, Supplies, and Fuel Inventory | 175 | 7,627 | (8,758) |
Regulatory Assets | (3,942) | (12,147) | 18,002 |
Accounts Payable and Accrued Charges | 9,790 | 14,284 | (13,917) |
Regulatory Liabilities | (20,227) | 18,012 | 10,921 |
Other, Net | 3,977 | 14,777 | (797) |
Net Cash Flows—Operating Activities | 448,324 | 425,468 | 364,934 |
Cash Flows from Investing Activities | |||
Capital Expenditures | (345,617) | (250,360) | (333,841) |
Purchase, Springerville Coal Handling Facilities Lease Assets | 0 | 0 | (120,312) |
Purchase, Springerville Unit 1 Assets | 0 | (85,000) | (45,753) |
Purchase Intangibles, Renewable Energy Credits | (51,179) | (40,949) | (29,184) |
Proceeds from Sale, Springerville Coal Handling Facilities | 0 | 0 | 23,656 |
Contributions in Aid of Construction | 4,983 | 3,432 | 4,517 |
Net Cash Flows—Investing Activities | (391,813) | (372,877) | (500,917) |
Cash Flows from Financing Activities | |||
Proceeds from Borrowings, Revolving Credit Facility | 70,000 | 0 | 148,000 |
Repayments of Borrowings, Revolving Credit Facility | (35,000) | 0 | (233,000) |
Proceeds from Borrowings, Term Loan | 0 | 0 | 130,000 |
Repayments of Borrowings, Term Loan | 0 | 0 | (130,000) |
Proceeds from Issuance, Long-Term Debt | 0 | 0 | 299,019 |
Repayments, Long-Term Debt | 0 | 0 | (208,600) |
Dividends Paid to Parent | (70,000) | (50,000) | (50,000) |
Payments of Capital Lease Obligations | (15,571) | (14,079) | (13,464) |
Payment of Debt Issuance/Retirement Costs | (245) | (183) | (3,942) |
Contribution from Parent | 0 | 0 | 180,000 |
Other, Net | 481 | (4,871) | 1,458 |
Net Cash Flows—Financing Activities | (50,335) | (69,133) | 119,471 |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 6,176 | (16,542) | (16,512) |
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 43,325 | 59,867 | 76,379 |
Cash, Cash Equivalents, and Restricted Cash, End of Period | $ 49,501 | $ 43,325 | $ 59,867 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Utility Plant | ||
Plant in Service | $ 5,780,805 | $ 5,975,139 |
Utility Plant Under Capital Leases | 84,870 | 167,413 |
Construction Work in Progress | 160,288 | 129,955 |
Total Utility Plant | 6,025,963 | 6,272,507 |
Accumulated Depreciation and Amortization | (2,193,656) | (2,385,053) |
Accumulated Amortization of Capital Lease Assets | (63,605) | (104,648) |
Total Utility Plant, Net | 3,768,702 | 3,782,806 |
Investments and Other Property | 51,260 | 45,020 |
Current Assets | ||
Cash and Cash Equivalents | 37,701 | 35,962 |
Accounts Receivable, Net | 137,932 | 124,934 |
Fuel Inventory | 25,059 | 25,887 |
Materials and Supplies | 103,981 | 97,126 |
Regulatory Assets | 93,960 | 56,340 |
Derivative Instruments | 3,187 | 4,966 |
Other | 10,777 | 13,793 |
Total Current Assets | 412,597 | 359,008 |
Regulatory and Other Assets | ||
Regulatory Assets | 293,551 | 225,453 |
Derivative Instruments | 8,826 | 330 |
Other | 55,313 | 37,372 |
Total Regulatory and Other Assets | 357,690 | 263,155 |
Total Assets | 4,590,249 | 4,449,989 |
Capitalization | ||
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of December 31, 2017 and 2016) | 1,296,539 | 1,296,539 |
Capital Stock Expense | (6,357) | (6,357) |
Retained Earnings | 380,076 | 273,408 |
Accumulated Other Comprehensive Loss | (6,226) | (4,555) |
Total Common Stock Equity | 1,664,032 | 1,559,035 |
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of December 31, 2017 and 2016) | 0 | 0 |
Capital Lease Obligations | 28,519 | 39,267 |
Long-term Debt | 1,354,423 | 1,453,072 |
Total Capitalization | 3,046,974 | 3,051,374 |
Current Liabilities | ||
Current Maturities of Long-Term Debt | 100,000 | 0 |
Borrowings Under Revolving Credit Facility | 35,000 | 0 |
Capital Lease Obligations | 10,749 | 51,765 |
Accounts Payable | 97,367 | 89,797 |
Accrued Taxes Other than Income Taxes | 40,706 | 37,639 |
Accrued Employee Expenses | 30,929 | 29,465 |
Accrued Interest | 14,750 | 14,508 |
Regulatory Liabilities | 89,024 | 76,069 |
Customer Deposits | 24,865 | 25,778 |
Derivative Instruments | 10,667 | 2,641 |
Other | 18,119 | 17,837 |
Total Current Liabilities | 472,176 | 345,499 |
Regulatory and Other Liabilities | ||
Deferred Income Taxes, Net | 300,258 | 529,148 |
Regulatory Liabilities | 516,438 | 300,700 |
Pension and Other Postretirement Benefits | 133,799 | 131,630 |
Derivative Instruments | 17,907 | 2,629 |
Other | 102,697 | 89,009 |
Total Regulatory and Other Liabilities | 1,071,099 | 1,053,116 |
Commitments and Contingencies | ||
Total Capitalization and Other Liabilities | $ 4,590,249 | $ 4,449,989 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Common Stock, No Par Value ($ per share) | $ 0 | $ 0 |
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, No Par Value ($ per share) | $ 0 | $ 0 |
Preferred Stock, Shares Authorized (in shares) | 1,000,000 | 1,000,000 |
Preferred Stock, Shares Outstanding (in shares) | 0 | 0 |
CONSOLIDATED STATEMENT OF CHANG
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY - USD ($) $ in Thousands | Total | Common Stock | Capital Stock Expense | Retained Earnings | Accumulated Other Comprehensive Loss |
Balances at December 31 at Dec. 31, 2014 | $ 1,215,779 | $ 1,116,539 | $ (6,357) | $ 111,523 | $ (5,926) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net Income | 127,794 | 127,794 | |||
Other Comprehensive Income, Net of Tax | 1,362 | 1,362 | |||
Dividends Declared to Parent | (50,000) | (50,000) | |||
Contribution from Parent | 180,000 | 180,000 | |||
Balances at December 31 at Dec. 31, 2015 | 1,474,935 | 1,296,539 | (6,357) | 189,317 | (4,564) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net Income | 124,438 | 124,438 | |||
Other Comprehensive Income, Net of Tax | 9 | 9 | |||
Dividends Declared to Parent | (50,000) | (50,000) | |||
Balances at December 31 at Dec. 31, 2016 | 1,559,035 | 1,296,539 | (6,357) | 273,408 | (4,555) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Adoption of ASU, Cumulative Effect Adjustment | 9,653 | 9,653 | |||
Net Income | 176,668 | 176,668 | |||
Other Comprehensive Income, Net of Tax | (1,671) | (1,671) | |||
Dividends Declared to Parent | (70,000) | (70,000) | |||
Balances at December 31 at Dec. 31, 2017 | $ 1,664,032 | $ 1,296,539 | $ (6,357) | $ 380,076 | $ (6,226) |
NATURE OF OPERATIONS AND SUMMAR
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 422,000 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 consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The 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's proportionate share of jointly-owned facilities is recorded in Utility Plant on the Consolidated Balance Sheets, and its proportionate share of the operating costs associated with these facilities is included in the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant. Certain amounts from prior periods have been reclassified to conform to the current year presentation. Accounting for Regulated Operations TEP applies accounting standards that recognize the economic effects of rate regulation. As a result, TEP capitalizes certain costs that would be recorded as expense or in AOCI by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in Retail Rates or in rates charged to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or amounts that are expected to be returned to customers through billing reductions in future periods. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. TEP evaluates regulatory assets and liabilities each period and believes future recovery or settlement is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 for additional information regarding regulatory matters. TEP applies regulatory accounting as the following conditions exist: • An independent regulator sets rates; • The regulator sets the rates to recover the specific enterprise’s costs of providing service; and • Rates are set at levels that will recover the entity’s costs and can be charged to and collected from ratepayers. Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder 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 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 December 31, 2017 , the carrying amount of assets and liabilities in the balance sheet that relates to variable interests under long-term PPAs is predominantly related to working capital accounts and generally represents 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 retail customer cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms. RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS Effective January 1, 2017, TEP adopted accounting guidance that requires the Company to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The adoption of this change in accounting principle did not have any impact on TEP's financial position or results of operations as the Company recovers the cost of inventory through its rates. Effective December 31, 2017, TEP early adopted accounting guidance that requires entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents on the cash flow statement. As a result, TEP no longer presents transfers between cash and cash equivalents and restricted cash and restricted cash equivalents on the cash flow statement. On adoption, using the retrospective method of transition, TEP's Consolidated Statements of Cash Flows included the following adjustments: As Filed Adoption of ASU Impacts As Adjusted (in millions) Year Ended December 31, 2016 Net Cash Flows—Operating Activities $ 425 $ — $ 425 Net Cash Flows—Investing Activities (376 ) 3 (373 ) Net Cash Flows—Financing Activities (69 ) — (69 ) Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash (20 ) 3 (17 ) Cash, Cash Equivalents, and Restricted Cash, Beginning of Period 56 4 60 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 36 $ 7 $ 43 (in millions) Year Ended December 31, 2015 Net Cash Flows—Operating Activities $ 365 $ — $ 365 Net Cash Flows—Investing Activities (503 ) 2 (501 ) Net Cash Flows—Financing Activities 120 — 120 Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash (18 ) 2 (16 ) Cash, Cash Equivalents, and Restricted Cash, Beginning of Period 74 2 76 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 56 $ 4 $ 60 The standard impacted the presentation of the cash flow statement but did not have an impact on TEP's financial position or results of operations. USE OF ACCOUNTING ESTIMATES Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect: • assets and liabilities in the balance sheet at the dates of the financial statements; • disclosures about contingent assets and liabilities at the dates of the financial statements; and • revenues and expenses in the income statement during the periods presented. Because these estimates involve judgments based upon the Company's evaluation of relevant facts and circumstances, actual results may differ from these estimates. Asset Retirement Obligations TEP has identified legal AROs related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its PV assets as a result of entering into various land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP primarily defers the accretion and depreciation expense associated with its legal AROs as regulatory assets based on the ACC approval of these costs in its depreciation rates. Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities. Contingencies Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these suits and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made. CASH AND CASH EQUIVALENTS TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents. RESTRICTED CASH Restricted cash includes cash balances restricted regarding 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: Years Ended December 31, (in millions) 2017 2016 2015 Cash and Cash Equivalents $ 38 $ 36 $ 56 Restricted Cash included in: Investments and Other Property 11 7 4 Current Assets, Other 1 — — Total Cash, Cash Equivalents, and Restricted Cash $ 50 $ 43 $ 60 Restricted cash included in Investments and Other Property on the Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan. Restricted cash included in Current Assets—Other represents cash required to be set aside by various contractual agreements. ALLOWANCE FOR DOUBTFUL ACCOUNTS TEP records an allowance for doubtful accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. Accounts receivable are charged-off in the period in which the receivable is deemed uncollectible. The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Consolidated Balance Sheets is summarized as follows: Years Ended December 31, (in millions) 2017 2016 2015 Beginning of Period $ 5 $ 27 $ 5 Additions Charged to Cost and Expense 3 4 2 Write-offs (3 ) (3 ) (3 ) Provision for Springerville Unit 1, Third-Party Owners — (23 ) 23 End of Period $ 5 $ 5 $ 27 The allowance for doubtful accounts decreased in 2016 due to the settlement and release of asserted claims between TEP and the Third-Party Owners related to Springerville Unit 1. See Note 7 for additional information regarding the settlement of the Third-Party Owners' claims. INVENTORY TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory. UTILITY PLANT Utility plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction (AFUDC), less contributions in aid of construction. The cost of repairs and maintenance, including planned generation overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no impact to the income statement. AFUDC and Capitalized Interest AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense on the Consolidated Statements of Income. The capitalized cost for equity funds is recorded in Other Income on the Consolidated Statements of Income. The average AFUDC rates on regulated construction expenditures are included in the table below: 2017 2016 2015 Average AFUDC Rates 7.31 % 7.47 % 6.12 % Depreciation Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 for additional information regarding utility plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC. Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. Below are the summarized average annual depreciation rates for all utility plant: 2017 2016 2015 Average Annual Depreciation Rates 2.97 % 2.85 % 2.83 % Utility Plant Under Capital Leases TEP finances a portion of the Springerville Common Facilities with capital leases. Capital lease expense is recorded in Amortization Expense and in Interest Expense—Capital Leases on the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant and Note 6 for additional information related to the lease terms. Computer Software Costs Costs incurred to purchase and develop internal use computer software are capitalized and amortized over the estimated economic life of the product. If the software is no longer useful or impaired, the carrying value is reduced and recorded as an expense on the income statement. EVALUATION OF ASSETS FOR IMPAIRMENT Long-lived assets and investments are evaluated for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates. DEFERRED FINANCING COSTS Using the effective interest method, costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. TEP accounts for debt issuance costs related to credit facility arrangements as an asset. The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt. OPERATING REVENUES Revenues related to the sale of energy are recognized when services or commodities are delivered to customers. The billing for the delivery of power to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates. Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events, if certain criteria are met. TEP charges customers the ACC-authorized tariff price plus separate ACC-authorized surcharges. TEP has identified its LFCR mechanism and DSM performance incentive as alternative revenues. 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. The LFCR surcharge is assessed as a percentage of the customer’s bill. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as the revenue is collected. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the 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, as approved in the 2017 Rate Order. In addition, the ACC approves a new DSM surcharge annually, which is effective June 1 of each year, to compensate TEP for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs are reflected in TEP’s non-fuel base rates as well as a performance incentive. TEP collects the DSM surcharge on a per kWh basis for residential customers and on a percentage of bill basis for non-residential customers. See Note 2 for additional information regarding regulatory matters. For purchased power and wholesale sales contracts that are settled financially, TEP nets the purchased power contracts with the sales contracts and reflects the amount in Wholesale Revenues on the Consolidated Statements of Income. TEP recognizes monthly management fees in Other Revenues on the Consolidated Statements of Income as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Additionally, Other Revenues includes reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and Springerville Coal Handling Facilities. The offsetting expenses are recorded in their respective line items on the income statement based on the nature of services provided. As the operating agent for Tri-State, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues on the Consolidated Statements of Income in the period earned. PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE TEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 2 for additional information regarding regulatory matters. RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025 , with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through the RES surcharge. The associated lost revenues attributable to meeting DG targets will be partially recovered through the LFCR mechanism. 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 . The EE Standards require increasing annual targeted retail kWh savings equal to 22% by 2020 . Any RES or DSM surcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the balance sheet as a regulatory liability or asset. TEP recognizes RES and DSM surcharge revenue in Retail Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures. RENEWABLE ENERGY CREDITS The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC mechanism. When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as other assets and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and other revenues in an equal amount. TEP had $42 million and $24 million of RECs as of December 31, 2017 and 2016 , respectively. RECs are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets. See Note 2 for additional information regarding regulatory matters. TAXES OTHER THAN INCOME TAXES TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement. INCOME TAXES Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not some portion, or the entire deferred income tax asset, will not be realized. Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense on the Consolidated Statements of Income. TEP accounts for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as regulatory liabilities and amortized as a reduction in income tax expense over the tax life of the underlying asset. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. All other federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises. TEP records income tax liabilities based on TEP's taxable income as reported in the consolidated tax return of FortisUS. PENSION AND OTHER POSTRETIREMENT BENEFITS TEP sponsors noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees. The Company recognizes the underfunded status of defined benefit pension plans as a liability in the balance sheet. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. TEP recognizes a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers. The Company expects recovery of these costs over the estimated service lives of employees. Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI. Pension and other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually. See Note 8 for additional information regarding the employee benefit plans. FAIR VALUE As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange. See Note 11 for additional information regarding fair value. DERIVATIVE INSTRUMENTS The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to meet forecasted load and reserve requirements, to reduce exposure to energy commodity price volatility, and to hedge interest rate risk exposure. Derivative instruments that do not meet the normal purchase or normal sale scope exception will be recognized as either assets or liabilities on the balance sheet and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity on the income statement. For derivatives designated as hedging contracts, TEP formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. Also, TEP formally documents hedging activity by transaction type and risk management strategy. For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. See Note 11 for additional information regarding derivative instruments. |
REGULATORY MATTERS
REGULATORY MATTERS | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
REGULATORY MATTERS | REGULATORY MATTERS The ACC and the FERC each regulate portions of 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 terms and prices of transmission services and wholesale electricity sales. 2017 RATE ORDER In February 2017, the ACC issued a rate order for new rates that took effect February 27, 2017. Provisions of the 2017 Rate Order include, but are not limited to: • a non-fuel base rate increase of $81.5 million , which includes $15 million of operating costs related to the 50.5% undivided interest in Springerville Unit 1 purchased by TEP in September 2016; • a 7.04% return on original cost rate base, which includes a cost of equity component of 9.75% and a cost of debt component of 4.32% ; • adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and • approval of a request to apply excess depreciation reserves against the unrecovered NBV of San Juan Unit 2 and the coal handling facilities at Sundt due to early retirement. The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2, which is currently expected to be completed in the first half of 2018. TEP cannot predict the outcome of these proceedings. FEDERAL TAX LEGISLATION - ACC DOCKET In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the ongoing benefits of the TCJA through to customers. TEP will actively participate in this docket and work with the ACC to reach an equitable solution. The Company cannot predict the outcome of these proceedings or how they may impact results of operations in the current or future years. See Note 12 for additional information regarding the TCJA. 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 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 PPFAC bank balance was over-collected by $9 million and $38 million as of December 31, 2017 and 2016 , respectively. In February 2017, the ACC approved a PPFAC credit to begin returning the over-collected PPFAC bank balance to customers. The table below presents TEP's PPFAC rates approved by the ACC: Period Cents per kWh March 2017 through March 2018 (0.20 ) May 2016 through February 2017 0.15 April 2015 through April 2016 0.68 October 2014 through March 2015 0.50 Renewable Energy Standard The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025 , with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must 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 . The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded performance-based incentives for customer-installed DG; and (iii) various other program costs. TEP recognized $1 million of revenue in 2017 as a return on company-owned solar projects. TEP is no longer requesting recovery on company-owned solar projects through the RES mechanism and plans to request recovery of these types of costs through its rate case process. TEP suspended its rooftop solar program effective December 2016, but requested approval of a community solar program. The ACC is expected to consider this program in Phase 2 of TEP's rate case. In 2017, the percentage of TEP's retail kWh sales attributable to the RES was approximately 10% , exceeding the overall 2017 RES requirement of 7% . Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain DG RECs, which are used to demonstrate compliance with the DG requirement, the ACC approved a waiver of the 2017 and 2018 residential distributed renewable energy requirement. Energy Efficiency Standards Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020 . As of December 31, 2017 , TEP’s cumulative annual energy savings were approximately 14% . 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 both 2017 and 2016 , and $3 million in 2015 related to performance, included in Retail Revenues on the Consolidated Statements of Income. In February 2016, the ACC approved TEP's 2016 energy efficiency implementation plan with a budget of approximately $22 million , which was partially offset by applying $8 million of previously recovered carryover funds. TEP has been approved to collect the remaining $14 million from retail customers through the DSM surcharge. Energy savings realized through the programs will count toward meeting the EE Standards and the associated lost revenue will be partially recovered through the LFCR mechanism. In June 2016, TEP notified the ACC that it would not file a 2017 energy efficiency implementation plan and instead continue the 2016 level of recovery through the end of 2017. TEP reduced its costs and incentive levels for certain programs in order to minimize any potential under-collected DSM balance at the end of 2017. In August 2017, TEP submitted its application for the 2018 energy efficiency implementation plan with a budget of $23 million and requested a waiver of the 2018 EE Standard. TEP expects to receive a decision on its 2018 energy efficiency implementation plan in the first half of 2018. 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 the 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, as approved in the 2017 Rate Order. TEP recorded regulatory assets and recognized LFCR revenues of $22 million in 2017 , $18 million in 2016 , and $12 million in 2015 . LFCR revenues are included in Retail Revenues on the Consolidated Statements of Income. REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: Remaining Recovery Period (years) December 31, ($ in millions) 2017 2016 Regulatory Assets Pension and Other Postretirement Benefits (Note 8) Various $ 126 $ 128 Early Generation Retirement Costs (1) Various 84 — Income Taxes Recoverable through Future Rates (2) Various 40 29 Final Mine Reclamation and Retiree Healthcare Costs (3) 20 31 27 Lost Fixed Cost Recovery 1 29 23 Property Tax Deferrals (4) 1 24 23 Springerville Unit 1 Leasehold Improvements (5) 6 14 17 Sundt Coal Handling Facilities (6) N/A — 14 Other Regulatory Assets Various 40 20 Total Regulatory Assets 388 281 Less Current Portion 1 94 56 Total Non-Current Regulatory Assets $ 294 $ 225 Regulatory Liabilities Income Taxes Payable through Future Rates (2) Various $ 353 $ 3 Net Cost of Removal (7) Various 180 270 Renewable Energy Standard Various 44 32 Deferred Investment Tax Credits (8) Various 14 23 Purchased Power and Fuel Adjustment Clause 1 9 38 Other Regulatory Liabilities Various 5 11 Total Regulatory Liabilities 605 377 Less Current Portion 1 89 76 Total Non-Current Regulatory Liabilities $ 516 $ 301 (1) Includes the NBV and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Consolidated Balance Sheets due to the planned early retirement of the facilities. As of December 31, 2017 , Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. See Note 3 for additional information related to the planned early retirement of Navajo and Sundt Units 1 and 2. (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. See Note 1 and Note 12 for additional information regarding income taxes. (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 fully recover these costs through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2037 . (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 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 amortization period. (6) In June 2014, the EPA issued a final rule that required TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continued to use coal as a fuel source; or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. TEP applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. (7) Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. As a result of the 2017 Rate Order, $87 million was transferred from Net Cost of Removal to Accumulated Depreciation and Amortization to reflect the impact of the revised depreciation study on the estimated cost of removal. (8) 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, TEP does not pay a return on regulatory liabilities. FERC COMPLIANCE In 2016, the FERC issued orders relating to certain late-filed TSAs, which resulted in TEP recording a liability and paying time-value refunds to the counterparties of these TSAs. In May 2017, the FERC informed TEP that the related investigation was closed. See Note 7 for additional information related to FERC compliance associated with these transmission contracts. IMPACTS OF REGULATORY ACCOUNTING If TEP determines that it no longer meets the criteria for continued application of regulatory accounting, TEP would be required to write off its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on TEP's financial statements. |
UTILITY PLANT AND JOINTLY-OWNED
UTILITY PLANT AND JOINTLY-OWNED FACILITIES | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Utility Plant And Jointly Owned Facilities | UTILITY PLANT AND JOINTLY-OWNED FACILITIES UTILITY PLANT The following table shows Plant in Service on the Consolidated Balance Sheets by major class: Annual Depreciation Rate (4) Average Remaining Life in Years (4) December 31, ($ in millions) 2017 2016 Plant in Service Generation Plant 3.19% 25 $ 2,548 $ 2,866 Transmission Plant 1.48% 32 1,001 1,024 Distribution Plant 1.56% 36 1,632 1,512 General Plant 5.89% 12 389 381 Intangible Plant, Software Costs, and Other (1) Various Various 207 185 Plant Held for Future Use — — 4 7 Total Plant in Service (2) $ 5,781 $ 5,975 Utility Plant Under Capital Leases (3) $ 85 $ 167 (1) Primarily represents computer software. Unamortized computer software costs were $59 million and $52 million as of December 31, 2017 and 2016 , respectively. The amortization of computer software costs was $19 million in 2017 , $17 million in 2016 , and $14 million in 2015 . Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and average remaining life of three years for large enterprise software. (2) Includes plant acquisition adjustments of $(134) million and $(139) million as of December 31, 2017 and 2016 , respectively. (3) In December 2017, TEP completed the purchase of an undivided ownership interest in the Springerville Common Facilities. See Note 6 for additional information regarding the Springerville leases. (4) Represents a composite of the depreciation rates of assets within each major class of utility plant and is based on the 2015 depreciation study available for the major classes of Plant in Service. TEP implemented new depreciation rates effective March 1, 2017, as approved in the 2017 Rate Order. Utility Plant Under Capital Leases All assets included in Utility Plant Under Capital Leases are used in generation operations and amortized over the primary lease term. The following table shows the amount of lease expense incurred for capital leases: Years Ended December 31, (in millions) 2017 2016 2015 Lease Expense Interest Expense included in: Interest Expense, Capital Leases $ 3 $ 3 $ 4 Amortization of Capital Lease Assets included in: Operating Expenses, Fuel — — 2 Operating Expenses, Amortization 6 5 6 Total Lease Expense $ 9 $ 8 $ 12 Springerville Acquisitions In September 2016, TEP purchased an undivided interest in Springerville Unit 1. The purchase increased TEP's total ownership interest to 100% . In December 2017, TEP purchased an undivided interest in the Springerville Common Facilities. As of December 31, 2017 , Utility Plant Under Capital Leases represented a 32.2% undivided interest in certain Springerville Common Facilities. See Note 6 for additional information regarding the Springerville capital lease purchases. JOINTLY-OWNED FACILITIES As of December 31, 2017 , TEP was a participant in the following jointly-owned generation facilities and transmission systems: (in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value San Juan Unit 1 50.0% $ 274 $ 6 $ 83 $ 197 Four Corners Units 4 and 5 7.0% 113 54 79 88 Luna 33.3% 55 — 3 52 Gila River Unit 3 75.0% 203 3 60 146 Gila River Common Facilities 18.8% 25 — 8 17 Springerville Coal Handling Facilities 83.0% 202 — 81 121 Transmission Facilities Various 483 5 247 241 Total $ 1,355 $ 68 $ 561 $ 862 As participants in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs for the above facilities. The Company accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation. RETIREMENTS San Juan Generating Station In October 2014, the EPA published a final rule approving a SIP covering BART requirements for San Juan, which included the closure of Units 2 and 3 by December 2017. TEP is a participant in San Juan Units 1 and 2. Given the closure of Units 2 and 3 and the desire of certain participants to exit their ownership in San Juan, PNM, TEP, and the other participants negotiated restructured ownership agreements which became effective upon the sale of San Juan Coal Company (SJCC) stock in January 2016. Under the new restructured ownership agreements, TEP and the other remaining participants have the option to exit their remaining ownership interests in San Juan as of June 30, 2022. In 2017, TEP recorded the early retirement San Juan Unit 2 and applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. The Consolidated Balance Sheets reflect a $224 million decrease in Plant in Service and Accumulated Depreciation and Amortization related to San Juan Unit 2. On December 20, 2017, San Juan Unit 2 was removed from service. See Note 2 for additional information regarding the 2017 Rate Order. Navajo Generating Station In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP is currently recovering Navajo's capital and operating costs in base rates using a useful life of 2030. As a result of the planned early retirement of Navajo, $52 million of the facility's NBV and other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of December 31, 2017 . See Note 2 for additional information related to the planned early retirement of Navajo. Sundt Generating Station In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source to comply with the EPA rules and transferred the NBV of the coal handling facilities at Sundt to a regulatory asset. As approved in the 2017 Rate Order, TEP applied excess depreciation reserves against the regulatory asset as of December 31, 2017 . See Note 2 for additional information regarding the 2017 Rate Order. In 2017, TEP submitted an Air Quality Permit Application (Application) to the Pima County Department of Environmental Quality (PDEQ) related to a generation modernization project at Sundt that will add generation capacity in the form of RICE generators in 2019 and 2020. As part of the Application, TEP plans to early retire Sundt Units 1 and 2 by the end of 2020. TEP is currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives of 2028 and 2030, respectively. As a result of the planned early retirement, $31 million of the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of December 31, 2017 . See Note 2 for additional information related to the planned early retirement of Sundt Units 1 and 2. ASSET RETIREMENT OBLIGATIONS The accrual of AROs is primarily related to generation and PV assets and is included in Regulatory and Other Liabilities—Other on the Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets: December 31, (in millions) 2017 2016 Beginning of Period $ 33 $ 32 Liabilities Incurred 3 — Liabilities Settled (1 ) — Regulatory Deferral/Accretion Expense 2 2 Revisions to the Present Value of Estimated Cash Flows (1) 9 (1 ) End of Period $ 46 $ 33 (1) Primarily related to changes in expected cost estimates and the acceleration of asset retirement dates of certain generation facilities. |
ACCOUNTS RECEIVABLE
ACCOUNTS RECEIVABLE | 12 Months Ended |
Dec. 31, 2017 | |
Accounts Receivable, Net [Abstract] | |
Accounts Receivable | ACCOUNTS RECEIVABLE The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets: December 31, (in millions) 2017 2016 Customer $ 81 $ 74 Due from Affiliates (Note 5) 7 9 Unbilled 39 34 Other 16 13 Allowance for Doubtful Accounts (5 ) (5 ) Accounts Receivable, Net $ 138 $ 125 |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy Affiliates). These transactions include the sale and purchase of power and transmission services, common cost allocations, and 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 Consolidated Balance Sheets: December 31, (in millions) 2017 2016 Receivables from Related Parties UNS Electric $ 5 $ 7 UNS Gas 2 2 Total Due from Related Parties $ 7 $ 9 Payables to Related Parties SES $ 3 $ 2 UNS Energy 1 — Total Due to Related Parties $ 4 $ 2 The following table presents the components of related party transactions included in the Consolidated Statements of Income: Years Ended December 31, (in millions) 2017 2016 2015 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 7 $ 7 $ 6 Wholesale Revenues, UNS Electric (1) — — 2 Control Area Services, UNS Electric (2) 3 2 2 Common Costs, UNS Energy Affiliates (3) 16 14 12 Corporate Services, Fortis Affiliates (4) 2 — — Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) — 1 1 Supplemental Workforce, SES (5) 15 14 16 Corporate Services, UNS Energy (6) 5 7 7 Corporate Services, UNS Energy Affiliates (7) 5 4 1 (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) TEP provides non-tariffed goods and services to Fortis affiliate companies at the higher of fully burdened cost or fair market value. (5) 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. (6) 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 82% 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 $6 million in both 2017 and 2016 , and $5 million in 2015 . (7) 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. CONTRIBUTION FROM PARENT UNS Energy made no equity contributions to TEP in 2017 or 2016 . TEP received a contribution from UNS Energy of $180 million in 2015 . The contributions were used to repay revolving credit loans, redeem bonds, purchase additional generation capacity, and provide additional liquidity to TEP. DIVIDENDS PAID TO PARENT TEP declared and paid $70 million in dividends to UNS Energy in 2017 and $50 million in both 2016 and 2015 . |
DEBT, CREDIT FACILITY, AND CAPI
DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS | DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS DEBT Long-term debt matures more than one year from the date of the financial statements. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets: December 31, ($ in millions) Interest Rate Maturity Date 2017 2016 Notes 2011 Notes 5.15% 2021 $ 250 $ 250 2012 Notes 3.85% 2023 150 150 2014 Notes 5.00% 2044 150 150 2015 Notes 3.05% 2025 300 300 Tax-Exempt Local Furnishings Bonds 2010 Pima A 5.25% 2040 100 100 2012 Pima A 4.50% 2030 16 16 2013 Pima A 4.00% 2029 91 91 2013 Apache A (1) 1.41% 2032 100 100 Tax-Exempt Pollution Control Bonds 2009 Pima A 4.95% 2020 80 80 2009 Coconino A 5.13% 2032 15 15 2010 Coconino A (2) 1.76% 2032 37 37 2012 Apache A 4.50% 2030 177 177 Total Long-Term Debt (3) 1,466 1,466 Less Unamortized Discount and Debt Issuance Costs 12 13 Less Current Maturities of Long-Term Debt (1) 100 — Total Long-Term Debt, Net $ 1,354 $ 1,453 (1) The bonds are variable rate debt for which rates are reset monthly. The interest rate is calculated using a weighted average based on a percentage of an index equal to one-month LIBOR plus a credit spread. The bonds are subject to mandatory tender for purchase in November 2018, and were reclassified to Current Maturities of Long-Term Debt on the Consolidated Balance Sheets as of December 31, 2017 . (2) The bonds are variable rate debt for which rates are reset weekly. The interest rate is calculated using a weighted average and includes LOC fees and remarketing fees. The bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in February 2019. (3) As of December 31, 2017 , all of TEP's debt is unsecured, with the exception of the 2010 Coconino A variable rate bonds, which are backed by an LOC. DEBT ISSUANCES AND REDEMPTIONS Fixed Rate Debt In February 2015, TEP issued and sold $300 million aggregate principal amount of senior unsecured notes. TEP may redeem the notes prior to December 2024, with a make-whole premium plus accrued interest. On or after December 2024, TEP may redeem the notes at par plus accrued interest. In January 2015, TEP purchased $130 million aggregate principal amount of unsecured tax-exempt IDRBs issued in June 2008 by the Industrial Development Authority (IDA) of Pima County, Arizona for the benefit of TEP. The bonds were not remarketed and were subsequently retired in September 2017. Variable Rate Debt In August 2015, TEP redeemed two series of variable rate tax-exempt bonds at par with an aggregate principal amount of $79 million prior to maturity. In September 2015, TEP terminated the associated LOCs issued under a revolving credit facility. CREDIT FACILITY In October 2015, TEP entered into an unsecured credit agreement which replaced its previous credit agreements. The credit facility included: (i) a borrowing capacity of $250 million in revolving credit commitments; (ii) an LOC facility with a sublimit of $50 million ; and (iii) an original maturity date of October 2020 with a provision allowing TEP to request up to two one -year maturity extensions. As permitted by the credit agreement, TEP requested and was granted two one -year extensions. The facility's new maturity date is October 2022. Interest rates and fees under the credit facility are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.00% for Eurodollar loans or ABR with no spread for ABR loans. TEP expects that amounts borrowed under the credit agreement will be used for working capital and other general corporate purposes and that LOCs will be issued from time to time to support energy procurement and hedging transactions. As of December 31, 2017 , TEP had $35 million borrowings outstanding included in Current Liabilities on the Consolidated Balance Sheets. As of February 14, 2018 , there was $232 million available under the revolving credit commitments and LOC facilities. TEP's previous credit agreements provided for a total of $270 million in revolving credit commitments, LOCs supporting variable-rate, tax-exempt bonds, and a $130 million term loan commitment, with original expiration dates of November 2016 and November 2015, respectively. 2010 REIMBURSEMENT AGREEMENT In December 2010, a $37 million LOC was issued to support certain variable rate tax-exempt bonds pursuant to the 2010 Reimbursement Agreement. The LOC has an expiration date of February 2019. Fees are payable on the aggregate outstanding amount of the LOC at a rate of 0.75% per annum based on TEP's current credit ratings. COVENANT COMPLIANCE Certain of TEP's credit and long-term debt agreements contain restrictive covenants, including restrictions on additional indebtedness, liens to secure indebtedness, mergers, sales of assets, transactions with affiliates, and restricted payments. As of December 31, 2017 , TEP was in compliance with the terms of its credit and long-term debt agreements. CAPITAL LEASE OBLIGATIONS The following table details Capital Lease Obligations on the Consolidated Balance Sheets: December 31, (in millions) 2017 2016 Capital Lease Obligations $ 39 $ 91 Less Current Obligations Under Capital Leases 11 52 Total Capital Lease Obligations, Non-Current $ 28 $ 39 Springerville Unit 1 Capital Lease Purchases In January 2015, upon expiration of the lease term, TEP purchased leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million , the appraised value. With the completion of the purchase, TEP owned 49.5% of Springerville Unit 1, or 192 MW of capacity. In September 2016, TEP purchased the remaining undivided interest in Springerville Unit 1 for $85 million , bringing its total ownership of the assets to 100% and total generating capacity to 387 MW. See Note 7 for more information regarding the settlement agreement relating to Springerville Unit 1. Springerville Coal Handling Facilities Lease Purchase In April 2015, upon expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million , bringing its total ownership of the assets to 100% . Upon purchase of the leased interest, TEP reduced Capital Lease Obligations on the Consolidated Balance Sheets for the purchase price. In May 2015, SRP, the owner of Springerville Unit 4, purchased from TEP a 17.05% undivided interest in the Springerville Coal Handling Facilities for approximately $24 million . Springerville Common Facilities Leases As of December 31, 2017, the Springerville Common Facilities Leases include two leases with a total fixed price purchase options of $68 million and initial terms ending January 2021. Under the two leases, TEP has options to: (i) renew the leases for periods of two or more years; or (ii) exercise the fixed price purchase options under these contracts. In addition, TEP entered into agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions if the Common Facilities Leases are not renewed: (i) TEP will exercise the purchase options under these contracts; (ii) SRP will be obligated to buy a 14% undivided interest in the facilities; and (iii) Tri-State will be obligated to either: (a) buy a 14% undivided interest in the facilities; or (b) continue to make payments to TEP for the use of these facilities. In December 2017, T EP purchased a 17.8% undivided interest in the Springerville Common Facilities for $38 million , bringing its total ownership of the assets to 67.8% . Upon purchase of the leased interest, TEP reduced Current Lease Obligations on the Consolidated Balance Sheets by $36 million . Springerville Common Facilities Lease Interest Rate Swap TEP entered into an interest rate swap agreement in 2006 that hedges a portion of the floating interest rate risk associated with the Springerville Common Facilities lease debt. The swap has the effect of fixing the benchmark LIBOR rate on a portion of the amortizing principal balance. The swap matures in January 2020 with interest on the lease debt payable at a swapped rate of 5.77% plus an applicable margin per the lease agreement. The lease debt outstanding as of December 31, 2017 consisted of a notional amount of $18 million on which interest was fixed by the swap and a notional amount of $3 million of debt that was not hedged. The applicable margin was 1.88% as of December 31, 2017 and 2016 . TEP recorded the interest rate swap as a cash flow hedge for financial reporting purposes. See Cash Flow Hedges in Note 11 for additional information. DEBT MATURITIES Long-term debt, including revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates: (in millions) Long-Term Debt (1) Capital Lease Obligations Total Debt Maturities (2) 2018 $ 100 $ 11 $ 111 2019 37 11 48 2020 80 18 98 2021 250 — 250 2022 — — — Total 2018 - 2022 467 40 507 Thereafter 999 — 999 Less: Imputed Interest — (1 ) (1 ) Total $ 1,466 $ 39 $ 1,505 (1) $37 million of TEP’s variable rate bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in February 2019. Although the variable rate bond matures in 2032, the above table reflects a redemption or repurchase of such bond in 2019 as though the LOC terminates without replacement upon expiration of the 2010 Reimbursement Agreement. TEP's 2013 tax-exempt variable rate IDRBs, which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in November 2018. (2) Total long-term debt excludes $10 million of related unamortized debt issuance costs and $2 million of unamortized original issue discount. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES COMMITMENTS As of December 31, 2017 , TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases: (in millions) 2018 2019 2020 2021 2022 Thereafter Total Fuel, Including Transportation $ 82 $ 83 $ 73 $ 43 $ 24 $ 244 $ 549 Purchased Power 29 — — — — — 29 Transmission 19 19 8 4 1 8 59 Renewable Power Purchase Agreements 64 64 63 63 63 668 985 RES Performance-Based Incentives 8 8 7 7 7 46 83 Operating Leases (1) 1 1 1 1 1 3 8 Land Easements and Rights-of-Way 1 1 1 2 2 82 89 Total Purchase Commitments $ 204 $ 176 $ 153 $ 120 $ 98 $ 1,051 $ 1,802 (1) Primarily represents leases for land, rail cars, and office facilities with varying terms, provisions, and expiration dates through 2036 . TEP's operating lease expense totaled $1 million in 2017 , $2 million in 2016 , and $3 million in 2015 . Costs for Purchased Power, Transmission, and Fuel, Including Transportation, are recoverable from customers through the PPFAC mechanism. A portion of the costs of PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. PBIs costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms. Fuel, Including Transportation TEP has long-term agreements for the purchase and delivery of coal with various expiration dates between 2020 and 2031 . Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these agreements include price adjustment components that will affect future costs. TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2018 and 2040 . In January 2018, TEP entered into a transportation agreement with EPNG extending the expiration date of the existing agreement from April 2018 to April 2023. Estimated future payments not included in the table above are: $4 million in 2018; $5 million in 2019 through 2022; and $1 million through the end of the contract. Purchased Power TEP has contracts with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity and energy payments based on actual power taken under the contracts with various expiration dates through the fourth quarter of 2018 . Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on projected market prices as of December 31, 2017 . Transmission TEP has agreements with other utilities to purchase transmission services over lines that are part of the Western Interconnection, a regional grid in the United States. These agreements expire in various years between 2019 and 2030 . Renewable Power Purchase Agreements TEP enters into long-term renewable PPAs which require TEP to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. While TEP is not required to make payments under the agreements if power is not delivered, estimated future payments are included in the table above. These agreements expire in various years between 2027 and 2036 . RES Performance-Based Incentives TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. These agreements expire in various years between 2020 and 2034 . Land Easements and Rights-of-Way Land Easements and Rights-of-Way have varying terms and provisions, and various expiration dates through 2054 . In November 2017, the Navajo Nation approved an extension for the use of their land. The extension, signed by TEP and the co-owners of Navajo, commences in December 2019 and ends in December 2054. The Navajo Nation has until December 2018 to select one of five different rental payments options provided for in the extension. The table above includes TEP's 7.5% ownership share of the option which, in management's opinion, is most probable to occur. The total obligation estimated under this option is $8 million commencing in 2019 through 2053. Under the remaining payment options, TEP's share of estimated total payment obligation ranges from $3 million to $8 million with various payment schedules with dates ranging from 2019 through 2053. 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 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 Springerville Generating Station Unit 1 In February 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (Agreement). In September 2016, TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased the Third-Party Owners’ undivided interest in Springerville Unit 1 for $85 million . As also provided for in the Agreement, TEP received $12.5 million from the Third-Party Owners in full satisfaction of all previously unreimbursed operating costs, which TEP recorded in Operating Revenues—Other on the Consolidated Statements of Income. Following the purchase, all outstanding disputes, pending litigation, and arbitration proceedings between TEP and the Third-Party Owners were dismissed with prejudice. 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 (OSM) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to SJCC 's San Juan mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSM, 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 OSM so the OSM 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 OSM’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. TEP cannot currently predict the outcome of this matter or the range of its potential impact. Claims Related to Four Corners Generating Station Endangered Species Act On April 20, 2016, several environmental groups filed a lawsuit in the U.S. District Court for the District of Arizona against the OSM and other federal agencies under the Endangered Species Act (ESA) alleging that the OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the U.S. Department of the Interior’s review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. This review process also required separate environmental impact evaluations under the NEPA and culminated in the issuance of a Record of Decision justifying the agency action extending the life of Four Corners and the adjacent Navajo Mine. In addition, the lawsuit alleges that these federal agencies violated both the ESA and the NEPA in providing the federal approvals necessary to extend operations at Four Corners and Navajo Mine past July 6, 2016. The lawsuit seeks various forms of relief, including a finding that the federal defendants violated the ESA and the NEPA by issuing the Record of Decision, setting aside and remanding the Biological Opinion and Record of Decision, and enjoining the federal defendants from authorizing any elements of the Four Corners and Navajo Mine pending compliance with NEPA. In July 2016, the defendants answered the complaint and APS, the operator of Four Corners, filed a motion to intervene in this matter. APS’ motion was granted in August 2016. In September 2016, Navajo Transitional Energy Company, LLC (NTEC), the company that owns the Navajo Mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC’s tribal sovereign immunity. In September 2017, the court granted NTEC’s motion to dismiss and dismissed the case with prejudice. In November 2017, the plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit the District Court’s decision to dismiss the case. TEP cannot currently predict the outcome of this matter or the range of its potential impact. Mine Reclamation at Generating 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 share of reclamation costs at all three mines is expected to be $61 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The Consolidated Balance Sheets reflect a total liability related to reclamation of $34 million and $26 million as of December 31, 2017 and 2016 , respectively. 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 to the coal suppliers. FERC Compliance In 2015 and 2016, TEP self-reported to the FERC Office of Enforcement (OE) that the Company had not timely filed certain FERC-jurisdictional agreements. TEP conducted comprehensive internal reviews of its compliance with the FERC filing requirements (Compliance Reviews), and made compliance filings with the FERC Office of Energy Market Regulation. This included the filing of several TSAs entered into between 2003 and 2015 that contained certain deviations from TEP’s standard service agreement form. In 2016, as a result of the FERC Refund Orders and ongoing discussions with the OE, TEP recorded a liability for the time-value refunds with a corresponding offset in revenues on its financial statements in 2016 . In 2016 , Wholesale Revenues on the Consolidated Statements of Income reflected $22 million , and, as of December 31, 2016 , Current Liabilities—Other on the Consolidated Balance Sheets reflected $5 million related to the time-value refunds. In June 2016, to preserve its rights, TEP petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the FERC Refund Orders. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement regarding the FERC Refund Orders. In accordance with the agreement, the counterparty paid TEP $8 million , which TEP recorded in Other Income on the Consolidated Statements of Income and dismissed the appeal with prejudice in January 2017. In May 2017, the FERC informed TEP that: (i) no further enforcement actions were necessary regarding the late-filed TSAs; and (ii) the related investigation was closed. As management no longer believed a loss was probable, TEP reversed the $5 million remaining balance related to potential time-value refunds in Current Liabilities—Other on the Consolidated Balance Sheets, offsetting Wholesale Revenues on the Consolidated Statements of Income. 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 December 31, 2017 , there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expires in 2019, San Juan in 2022, Four Corners in 2041, and Luna in 2046. |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 12 Months Ended |
Dec. 31, 2017 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract] | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS PENSION BENEFIT PLANS TEP has three noncontributory, defined benefit pension plans. Benefits are based on years of service and average compensation. Two of the plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) regulations. TEP also maintains a SERP for executive management. OTHER POSTRETIREMENT BENEFITS PLAN TEP provides limited healthcare and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. TEP funds its other postretirement benefits for classified employees through a VEBA. TEP contributed $3 million in 2017 , $2 million in 2016 , and $4 million in 2015 to the VEBA. Other postretirement benefits for unclassified employees are self-funded. REGULATORY RECOVERY TEP records changes in non-SERP pension and other postretirement defined benefit plans, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in the rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income since SERP expense is not currently recoverable in rates. The following table presents pension and other postretirement benefit amounts (excluding tax balances) included on the Consolidated Balance Sheets: Pension Benefits Other Postretirement Benefits December 31, (in millions) 2017 2016 2017 2016 Regulatory Assets $ 121 $ 123 $ 5 $ 5 Accrued Employee Expenses (1 ) (1 ) (2 ) (2 ) Pension and Other Postretirement Benefits (71 ) (69 ) (63 ) (63 ) Accumulated Other Comprehensive Loss, SERP 9 6 — — Net Amount Recognized $ 58 $ 59 $ (60 ) $ (60 ) OBLIGATIONS AND FUNDED STATUS The Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations as of December 31, 2017 and 2016 . The table below presents the status of all of TEP’s pension and other postretirement benefit plans. All plans have projected benefit obligations in excess of the fair value of plan assets for each period presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2017 2016 2017 2016 Change in Benefit Obligation Beginning of Period $ 424 $ 394 $ 79 $ 78 Actuarial Loss 42 20 1 — Interest Cost 15 15 2 2 Service Cost 13 12 4 4 Benefits Paid (19 ) (17 ) (4 ) (5 ) End of Period 475 424 82 79 Change in Fair Value of Plan Assets Beginning of Period 354 336 14 13 Actual Return on Plan Assets 59 27 2 1 Benefits Paid (19 ) (17 ) (4 ) (5 ) Employer Contributions (1) 9 8 5 5 End of Period 403 354 17 14 Funded Status at End of Period $ (72 ) $ (70 ) $ (65 ) $ (65 ) (1) TEP expects to contribute $11 million to the pension plans in 2018 . The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2017 2016 2017 2016 Net Loss $ 129 $ 128 $ 5 $ 6 Prior Service Cost (Benefit) 1 — (1 ) (1 ) The accumulated benefit obligation aggregated for all pension plans is $428 million and $384 million as of December 31, 2017 and 2016 , respectively. Two of the pension plans had accumulated benefit obligations in excess of plan assets as of December 31, 2017 , compared to three as of December 31, 2016 , as a result of market gains on plan assets in 2017. The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets: December 31, (in millions) 2017 2016 Accumulated Benefit Obligation $ 237 $ 384 Fair Value of Plan Assets 206 354 Beginning in 2016, the Company elected to measure service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Prior to 2016, the Company measured service and interest costs for pension and other postretirement benefits utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. TEP believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans' liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of its plan obligations nor the funded status. TEP accounted for this change as a change in accounting estimate, and accordingly, accounted for it on a prospective basis. Net periodic benefit plan cost includes the following components: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2017 2016 2015 2017 2016 2015 Service Cost $ 13 $ 12 $ 12 $ 4 $ 4 $ 4 Interest Cost 15 15 17 2 2 3 Expected Return on Plan Assets (25 ) (23 ) (23 ) (1 ) (1 ) (1 ) Amortization of Net Loss 8 7 7 — — — Net Periodic Benefit Cost $ 11 $ 11 $ 13 $ 5 $ 5 $ 6 Approximately 18% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income. The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI were as follows: Pension Benefits Other Postretirement Benefits Regulatory Asset AOCI Regulatory Asset (in millions) 2017 2016 2015 2017 2016 2015 2017 2016 2015 Current Year Actuarial (Gain) Loss $ 5 $ 15 $ 5 $ 3 $ 1 $ — $ (1 ) $ — $ (4 ) Amortization of Net Loss (7 ) (7 ) (7 ) — — — — — — Total Recognized (Gain) Loss $ (2 ) $ 8 $ (2 ) $ 3 $ 1 $ — $ (1 ) $ — $ (4 ) For all pension plans, TEP amortizes prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. Estimated amortization from regulatory assets into net periodic benefit cost in 2018 includes the following: (in millions) Pension Benefits Other Postretirement Benefits Net Loss $ 7 $ — Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. TEP uses a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25 th percentile to the 75 th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward-looking return expectations only. The above method is used for all asset classes. The following table includes the weighted average assumptions used to determine benefit obligations: Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Discount Rate 3.7% 4.2% 3.6% 4.0% Rate of Compensation Increase 2.8% 2.8% N/A N/A The following table includes the weighted average assumptions used to determine net periodic benefit costs: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Discount Rate, Service Cost 4.4% 4.8% 4.2% 4.3% 4.6% 3.9% Discount Rate, Interest Cost 3.7% 3.9% 4.2% 3.3% 3.4% 3.9% Rate of Compensation Increase 2.8% 3.0% 3.0% N/A N/A N/A Expected Return on Plan Assets 7.0% 7.0% 7.0% 7.0% 7.0% 7.0% Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached: December 31, 2017 2016 Next Year 7.6% 7.6% Ultimate Rate Assumed 4.5% 4.5% Year Ultimate Rate is Reached 2036 2037 Assumed healthcare cost trend rates significantly affect the amounts reported for healthcare plans. A one-percentage-point change in assumed healthcare cost trend rates would have the following effects on the amounts: One-Percentage- Point Increase One-Percentage- Point Decrease (in millions) December 31, 2017 Increase (Decrease) on Total Service and Interest Cost Components $ 1 $ (1 ) Increase (Decrease) on Other Postretirement Benefits Obligation 7 (6 ) PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT ASSETS TEP calculates the fair value of plan assets on December 31, the measurement date. Asset allocations, by asset category, on the measurement date were as follows: Pension Other Postretirement Benefits 2017 2016 2017 2016 Asset Category Equity Securities 46 % 49 % 63 % 60 % Fixed Income Securities 45 % 41 % 35 % 35 % Real Estate 7 % 8 % — % 2 % Other 2 % 2 % 2 % 3 % Total 100 % 100 % 100 % 100 % As of December 31, 2017 , the fair value of VEBA trust assets was $17 million , of which $6 million were fixed income investments and $11 million were equities. As of December 31, 2016 , the fair value of VEBA trust assets was $14 million , of which $5 million were fixed income investments and $9 million were equities. The VEBA trust assets are primarily Level 2. There are no Level 3 assets in the VEBA trust. The following tables present the fair value measurements of pension plan assets by level within the fair value hierarchy: Level 1 Level 2 Level 3 Total (in millions) December 31, 2017 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 66 — 66 United States Small Cap — 19 — 19 Non-United States — 72 — 72 Global — 30 — 30 Fixed Income — 179 — 179 Real Estate — 9 21 30 Private Equity — — 6 6 Total $ 1 $ 375 $ 27 $ 403 (in millions) December 31, 2016 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 61 — 61 United States Small Cap — 18 — 18 Non-United States — 67 — 67 Global — 28 — 28 Fixed Income — 144 — 144 Real Estate — 9 19 28 Private Equity — — 7 7 Total $ 1 $ 327 $ 26 $ 354 • Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. • Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund. • Level 3 real estate investments values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of similar properties. • Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models. The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. (in millions) Private Equity Real Estate Total Balance as of December 31, 2015 $ 7 $ 18 $ 25 Actual Return on Plan Assets: Assets Held at Reporting Date 1 1 2 Purchases, Sales, and Settlements (1 ) — (1 ) Balance as of December 31, 2016 7 19 26 Actual Return on Plan Assets: Assets Held at Reporting Date 1 2 3 Purchases, Sales, and Settlements (2 ) — (2 ) Balance as of December 31, 2017 $ 6 $ 21 $ 27 Pension Plan Investments Investment Goals Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. TEP considers the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. TEP expects to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk. Risk Management TEP recognizes the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. The Company recognizes some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: (i) plan status; (ii) plan sponsor financial status and profitability; (iii) plan features; and (iv) workforce characteristics. TEP determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes. Relationship between Plan Assets and Benefit Obligations The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via actuarial valuation. Target Allocation Percentages The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced. Pension Other Postretirement Benefits December 31, 2017 Cash/Treasury Bills —% 2% Equity Securities: United States Large Cap 16% 39% United States Small Cap 5% 5% Non-United States Developed 14% 7% Non-United States Emerging 4% 9% Global Equity 4% —% Global Infrastructure 3% —% Fixed Income 45% 38% Real Estate 8% —% Private Equity 1% —% Total 100% 100% Pension Fund Descriptions For each type of asset category selected by the Pension Committee, TEP's investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, TEP's investment consultant directs investments to a private equity manager that invests in third-parties’ funds. ESTIMATED FUTURE BENEFIT PAYMENTS TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate. (in millions) 2018 2019 2020 2021 2022 2023-2027 Pension Benefits $ 21 $ 22 $ 23 $ 24 $ 25 $ 137 Other Postretirement Benefits 5 5 5 6 6 30 DEFINED CONTRIBUTION PLAN TEP offers a defined contribution savings plan to all eligible employees. The Internal Revenue Code identifies the plan as a qualified 401(k) plan. Participants direct the investment of contributions to certain funds in their account. The Company matches part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $6 million in 2017 , and $5 million in both 2016 and 2015 . |
SHARE-BASED COMPENSATION
SHARE-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Share-based compensation | SHARE-BASED COMPENSATION 2015 SHARE UNIT PLAN The Human Resources and Governance Committee (Committee) of UNS Energy approved and UNS Energy's Board of Directors ratified the 2015 Share Unit Plan (Plan) effective January 2015. Under the Plan, key employees, including executive officers of UNS Energy and its subsidiaries, may be granted long-term incentive awards of performance-based share units (PSUs) and time-based restricted share units (RSUs) annually. Each PSU and RSU granted is valued based on one share of Fortis common stock traded on the Toronto Stock Exchange, converted to U.S. dollars. UNS Energy allocates the obligation and expense for this plan to its subsidiaries based on the Massachusetts Formula. The following table represents PSUs and RSUs awarded by UNS Energy: 2017 2016 2015 PSUs 68,126 66,974 47,776 RSUs 34,063 33,488 23,888 The awards are classified as liability awards based on the cash settlement feature. Liability awards are measured at their fair value at the end of each reporting period and will fluctuate based on the price of Fortis' common stock as well as the level of achievement of the financial performance criteria. The awards are payable on the third anniversary of the grant date. TEP's allocated share of probable payout was $9 million and $4 million as of December 31, 2017 and 2016 , respectively. TEP's allocated portion of compensation expense is recognized in Operations and Maintenance Expense on the Consolidated Statements of Income. Compensation expense associated with unvested PSUs and RSUs is recognized on a straight-line basis over the minimum required service period in an amount equal to the fair value on the measurement date or each reporting period. TEP recorded $4 million in 2017 , $2 million in 2016 , and $1 million in 2015 based on its share of UNS Energy's compensation expense. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION CASH TRANSACTIONS Years Ended December 31, (in millions) 2017 2016 2015 Interest, Net of Amounts Capitalized $ 61 $ 61 $ 65 Income Taxes (1) — — — (1) TEP did not pay federal or state income taxes due to net operating loss carryforwards offsetting taxable income. NON-CASH TRANSACTIONS Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows: Years Ended December 31, (in millions) 2017 2016 2015 Net Cost of Removal Increase (Decrease) (1) $ (88 ) $ 8 $ 1 Accrued Capital Expenditures 24 29 28 Commitment to Purchase Capital Lease Interests — 36 — Asset Retirement Obligations Increase (Decrease) (2) 10 (1 ) 3 (1) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In the 2017 Rate Order, the ACC authorized a new depreciation study for TEP modifying its depreciation reserves and rates. See Note 2 for additional information. (2) The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of the expected future AROs. |
FAIR VALUE MEASUREMENTS AND DER
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Text Block [Abstract] | |
FAIR VALUE MEASUREMENTS & 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. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented. 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) December 31, 2017 Assets Cash Equivalents (1) $ 30 $ — $ — $ 30 Restricted Cash (1) 12 — — 12 Energy Derivative Contracts, Regulatory Recovery (2) — 9 — 9 Energy Derivative Contracts, No Regulatory Recovery (2) — — 3 3 Total Assets 42 9 3 54 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (26 ) — (26 ) Energy Derivative Contracts, No Regulatory Recovery (2) — — (1 ) (1 ) Interest Rate Swap (3) — (1 ) — (1 ) Total Liabilities — (27 ) (1 ) (28 ) Total Assets (Liabilities), Net $ 42 $ (18 ) $ 2 $ 26 (in millions) December 31, 2016 Assets Cash Equivalents (1) $ 23 $ — $ — $ 23 Restricted Cash (1) 7 — — 7 Energy Derivative Contracts, Regulatory Recovery (2) — 3 — 3 Energy Derivative Contracts, No Regulatory Recovery (2) — — 2 2 Total Assets 30 3 2 35 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (2 ) (1 ) (3 ) Interest Rate Swap (3) — (2 ) — (2 ) Total Liabilities — (4 ) (1 ) (5 ) Total Assets (Liabilities), Net $ 30 $ (1 ) $ 1 $ 30 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the 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 Consolidated Balance Sheets. The valuation techniques are described below. (3) The Interest Rate Swap is valued using an income valuation approach based on the 6-month LIBOR and is included in Derivative Instruments on the Consolidated Balance Sheets. 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) December 31, 2017 Derivative Assets Energy Derivative Contracts $ 12 $ 10 $ — $ 2 Derivative Liabilities Energy Derivative Contracts (27 ) (10 ) — (17 ) Interest Rate Swap (1 ) — — (1 ) (in millions) December 31, 2016 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (3 ) (2 ) — (1 ) Interest Rate Swap (2 ) — — (2 ) 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. 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 in January 2020 . TEP had a purchased power swap to hedge the cash flow risk associated with a long-term power supply agreement which expired in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $1 million . Realized losses from cash flow hedges are shown in the following table: Years Ended December 31, (in millions) 2017 2016 2015 Capital Lease Interest Expense $ 1 $ 1 $ 2 Purchased Power — — 1 As of December 31, 2017 , the total notional amount of the interest rate swap was $18 million . Energy Derivative Contracts, Regulatory Recovery TEP records unrealized gains and losses on energy purchase contracts that are recoverable through the PPFAC mechanism on the balance sheet as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statement or in the statement of other comprehensive income, as shown in the following table: Years Ended December 31, (in millions) 2017 2016 2015 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ (18 ) $ 12 $ 6 Energy Derivative Contracts, No Regulatory Recovery TEP enters into certain contracts that qualify as derivatives, but do not meet the regulatory recovery criteria. 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. Derivative Volumes As of December 31, 2017 , TEP has energy contracts that will settle on various expiration dates through 2029 . The volumes associated with the energy contracts were as follows: December 31, 2017 2016 Power Contracts GWh 2,589 2,610 Gas Contracts BBtu (1) 137,952 12,355 (1) Increase in volume of gas contracts is a result of the planned early retirement of certain coal-fired generation. To reduce exposure to energy price risk associated with natural gas, the Company entered into longer term gas contracts increasing its overall volume outstanding in 2017. See Note 3 for additional information related to the planned early retirement of coal-fired generation. Level 3 Fair Value Measurements The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Fair Value of Range of Approach Assets Liabilities Unobservable Inputs Unobservable Input (in millions) December 31, 2017 Forward Power Contracts Market approach $ 3 $ (1 ) Market price per MWh $ 17.65 $ 34.60 (in millions) December 31, 2016 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 20.90 $ 40.00 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: Years Ended December 31, (in millions) 2017 2016 Beginning of Period $ 1 $ (2 ) Gains (Losses) Recorded Regulatory Assets or Liabilities, Derivative Instruments 1 2 Wholesale Revenues 4 4 Settlements (4 ) (3 ) End of Period $ 2 $ 1 Gains (Losses), Assets (Liabilities) still held $ 2 $ 1 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 measurement 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, a LOC, 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 $27 million as of December 31, 2017 , compared with $8 million as of December 31, 2016 . As of December 31, 2017 , TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on December 31, 2017 , TEP would have been required to post an additional $27 million of collateral of which $12 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. TEP uses the following methods and assumptions for estimating the fair value of financial instruments: • 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. • For long-term debt, TEP uses quoted market prices, when available, or calculates the present value of the remaining cash flows as of the balance sheet date. When calculating present value, the Company uses current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. The Company also incorporates the impact of its own credit risk using a credit default swap rate. 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 December 31, (in millions) 2017 2016 2017 2016 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,466 $ 1,547 $ 1,472 |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following: Years Ended December 31, (in millions) 2017 2016 2015 Federal Income Tax Expense at Statutory Rate $ 97 $ 64 $ 70 State Income Tax Expense, Net of Federal Deduction 9 6 8 Federal/State Tax Credits (9 ) (8 ) (8 ) Allowance for Equity Funds Used During Construction (2 ) (1 ) (1 ) Deferred Tax Asset Valuation Allowance — (2 ) 1 Impact of Enactment, TCJA 7 — — Other (1 ) — 2 Total Federal and State Income Tax Expense $ 101 $ 59 $ 72 Income tax expense included in the income statement consists of the following: Years Ended December 31, (in millions) 2017 2016 2015 Current Income Tax Expense Federal $ — $ — $ — State — — — Total Current Income Tax Expense — — — Deferred Income Tax Expense Federal 98 60 66 Federal Investment Tax Credits (6 ) (6 ) (6 ) State 9 5 12 Total Deferred Income Tax Expense 101 59 72 Total Federal and State Income Tax Expense $ 101 $ 59 $ 72 On December 22, 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017. In addition, the TCJA provides modifications to bonus depreciation rules and limitations on the deductibility of interest expense, both of which include carve-outs for regulated utilities. The Company was required to revalue its deferred tax assets and liabilities at the new federal corporate income tax rate as of the date of enactment of the TCJA. This resulted in a net decrease to deferred income tax liabilities. Since the Company believes it is probable that a significant portion of the decrease will be returned to customers through future rates, a regulatory liability was established. The impacts of the new tax law to the Company's financial results included: (i) a $7 million increase to Income Tax Expense on the Consolidated Statements of Income in 2017 ; and (ii) a $343 million net increase to Regulatory Liabilities and a $336 million net decrease to Deferred Income Tax Liabilities on the Consolidated Balance Sheets as of December 31, 2017 . TEP is still in the process of evaluating the bonus depreciation carve-out for regulated utilities and anticipates further clarification from the IRS. TEP has recorded an estimated provision for bonus depreciation for its fixed assets placed in service between September 27, 2017 and December 31, 2017, which impacts TEP’s Operating Loss Carryforward Deferred Tax Asset and Plant Deferred Tax Liability. The significant components of deferred income tax assets and liabilities consist of the following: December 31, (in millions) 2017 2016 Gross Deferred Income Tax Assets Capital Lease Obligations $ 10 $ 35 Operating Loss Carryforwards, Net 56 129 Customer Advances and Contributions in Aid of Construction 14 20 Alternative Minimum Tax Credit 26 25 Other Postretirement Benefits 15 23 Emission Allowance Inventory 3 9 Investment Tax Credit Carryforward 34 32 Income Taxes Recoverable Through Future Rates 88 — Other 47 60 Total Gross Deferred Income Tax Assets 293 333 Deferred Tax Assets Valuation Allowance — — Gross Deferred Income Tax Liabilities Plant, Net (518 ) (774 ) Plant Abandonments (21 ) — Capital Lease Assets, Net (5 ) (24 ) Pensions (16 ) (26 ) Income Taxes Payable Through Future Rates (10 ) — Other (23 ) (38 ) Total Gross Deferred Income Tax Liabilities (593 ) (862 ) Deferred Income Taxes, Net $ (300 ) $ (529 ) TEP recorded no valuation allowance against credit and loss carryforward deferred income tax assets as of December 31, 2017 and 2016. Management believes TEP will produce sufficient taxable income in the future to realize credit and loss carryforwards before they expire. As of December 31, 2017 , TEP had the following carryforward amounts: (in millions) Amount Expiring Year Federal Net Operating Loss $ 263 2031-35 State Credits 8 2021-29 Alternative Minimum Tax Credit 26 None Investment Tax Credits 34 2031-37 Uncertain Tax Positions A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: December 31, (in millions) 2017 2016 Beginning of Period $ 12 $ 5 Additions Based on Tax Positions Taken in the Current Year 7 7 Reduction to Positions, TCJA (6 ) — End of Period $ 13 $ 12 Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million as of December 31, 2017 and 2016 . TEP recorded no interest expense during 2017 , 2016 , or 2015 related to uncertain tax positions. In addition, TEP had no interest payable and no penalties accrued as of December 31, 2017 and 2016 . TEP has been audited by the IRS through tax year 2010. TEP is not currently under audit by any federal or state tax agencies. The balance in unrecognized tax benefits could change in the next 12 months as a result of IRS audits, but the Company is unable to determine the amount of change. |
RECENTLY ISSUED ACCOUNTING PRON
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Text Block [Abstract] | |
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS | RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS TEP considers the applicability and impact of all Accounting Standard Updates (ASU) issued by the Financial Accounting Standards Board (FASB). The following updates have been issued, but have not yet been adopted by TEP. Updates not listed below were assessed and either determined to not be applicable or are expected to have a minimal impact on TEP's consolidated financial position, results of operations, or disclosures. REVENUE FROM CONTRACTS WITH CUSTOMERS In May 2014, the FASB issued an ASU intended to enable users of financial statements to better understand and consistently analyze an entity's revenues across industries and transactions. The ASU was effective for annual and interim periods beginning January 1, 2018 and permits two implementation approaches: (i) retrospective application; or (ii) modified retrospective application by recognizing the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings on the date of adoption supplemented by additional disclosures. TEP adopted this ASU on January 1, 2018, using the modified retrospective approach, and did not identify or record any adjustment to the opening balance of retained earnings on adoption. Under the new standard, recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The adoption of this ASU did not affect revenue recognition for tariff-based sales to retail and wholesale customers, which represent TEP's primary source of revenue. Accordingly, the adoption of this standard did not have a material effect on TEP's financial statements. However, the presentation and disclosure requirements of the ASU will result in a change in the presentation of revenues on TEP's income statement as well as expanded disclosures. LEASES In February 2016, the FASB issued an ASU that will require the recognition of leased assets and liabilities by lessees for those leases classified as operating leases under current GAAP. The standard is effective for periods beginning January 1, 2019, and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. TEP is evaluating the impact of this ASU to its financial statements and disclosures. COMPENSATION—RETIREMENT BENEFITS In March 2017, the FASB issued an ASU to improve the presentation of net periodic benefit cost for pension and other postretirement benefits. TEP adopted this ASU on January 1, 2018, the effective date of the ASU. Effective in the first quarter of 2018, TEP will no longer capitalize the non-service cost components of net periodic benefit cost as part of inventory or plant in service and will present non-service costs retrospectively in Other Income—Other Expense on the Consolidated Statements of Income. The adoption of the ASU did not have a material impact on the Company's financial position or results of operations. DERIVATIVES AND HEDGING In August 2017, the FASB issued an ASU that enables entities to better align their risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance and the presentation of hedge results. The ASU expands an entity's ability to apply hedge accounting to non-financial and financial risk components and simplify fair value hedges of interest rate risk. The ASU eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The amendments to the ASU also ease hedge documentation and effectiveness assessments requirements under previous guidance. The standard is effective for fiscal years beginning January 1, 2019. Early adoption is permitted. The ASU is expected to have minimal impact to TEP's financial statements and disclosures. |
QUARTERLY FINANCIAL DATA (UNAUD
QUARTERLY FINANCIAL DATA (UNAUDITED) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
QUARTERLY FINANCIAL DATA (UNAUDITED) | QUARTERLY FINANCIAL DATA (UNAUDITED) TEP's quarterly financial information is unaudited, but, in management’s opinion, includes all adjustments necessary for a fair presentation. TEP's utility business is seasonal in nature. Peak sales periods for TEP generally occur during the summer. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. First Quarter Second Quarter Third Quarter Fourth Quarter (in millions) 2017 Operating Revenue $ 268 $ 352 $ 417 $ 304 Operating Income 37 107 138 44 Net Income 21 61 82 13 2016 Operating Revenue $ 243 $ 317 $ 394 $ 281 Operating Income 12 72 122 37 Net Income (Loss) (1 ) 41 72 12 |
NATURE OF OPERATIONS AND SUMM23
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis Of Presentation | BASIS OF PRESENTATION TEP's consolidated financial statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations. The 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's proportionate share of jointly-owned facilities is recorded in Utility Plant on the Consolidated Balance Sheets, and its proportionate share of the operating costs associated with these facilities is included in the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant. Certain amounts from prior periods have been reclassified to conform to the current year presentation. |
Variable Interest Entity | Variable Interest Entities TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder 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 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 December 31, 2017 , the carrying amount of assets and liabilities in the balance sheet that relates to variable interests under long-term PPAs is predominantly related to working capital accounts and generally represents 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 retail customer cost recovery mechanisms. |
Recently Adopted Accounting Pronouncements | RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS Effective January 1, 2017, TEP adopted accounting guidance that requires the Company to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The adoption of this change in accounting principle did not have any impact on TEP's financial position or results of operations as the Company recovers the cost of inventory through its rates. Effective December 31, 2017, TEP early adopted accounting guidance that requires entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents on the cash flow statement. As a result, TEP no longer presents transfers between cash and cash equivalents and restricted cash and restricted cash equivalents on the cash flow statement |
Use of Accounting Estimates | USE OF ACCOUNTING ESTIMATES Management uses estimates and assumptions when preparing financial statements according to GAAP. These estimates and assumptions affect: • assets and liabilities in the balance sheet at the dates of the financial statements; • disclosures about contingent assets and liabilities at the dates of the financial statements; and • revenues and expenses in the income statement during the periods presented. Because these estimates involve judgments based upon the Company's evaluation of relevant facts and circumstances, actual results may differ from these estimates. |
Asset Retirement Obligations | Asset Retirement Obligations TEP has identified legal AROs related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its PV assets as a result of entering into various land leases or land easement agreements. Liabilities are recorded for legal AROs in the period in which they are incurred if it can be reasonably estimated. When a new obligation is recorded, the cost of the liability is capitalized by increasing the carrying amount of the related long-lived asset. The increase in the liability due to the passage of time is recorded by recognizing accretion expense in Operations and Maintenance Expense on the Consolidated Statements of Income. Capitalized cost is depreciated over the useful life of the related asset or, when applicable, the term of the lease. TEP primarily defers the accretion and depreciation expense associated with its legal AROs as regulatory assets based on the ACC approval of these costs in its depreciation rates. Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. TEP recovers estimated future removal costs in Retail Rates and records an obligation for estimated costs of removal as regulatory liabilities. |
Contingencies | Contingencies Reserves for specific legal proceedings are established when the likelihood of an unfavorable outcome is probable and the amount of loss can be reasonably estimated. Significant judgment is required in predicting the outcome of these suits and claims, many of which take years to complete. TEP identifies certain other legal matters where the Company believes an unfavorable outcome is reasonably possible or no estimate of possible losses can be made. All contingencies are regularly reviewed to determine whether the likelihood of loss has changed and to assess whether a reasonable estimate of the loss or range of loss can be made. |
Cash and Cash Equivalents | CASH AND CASH EQUIVALENTS TEP considers all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents. |
Restricted Cash | RESTRICTED CASH Restricted cash includes cash balances restricted regarding withdrawal or usage based on contractual or regulatory considerations. Restricted cash included in Investments and Other Property on the Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan. Restricted cash included in Current Assets—Other represents cash required to be set aside by various contractual agreements. |
Allowance for Doubtful Accounts | ALLOWANCE FOR DOUBTFUL ACCOUNTS TEP records an allowance for doubtful accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. Accounts receivable are charged-off in the period in which the receivable is deemed uncollectible. |
Inventory | INVENTORY TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are capitalized as part of the cost of the inventory. |
Utility Plant | UTILITY PLANT Utility plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction (AFUDC), less contributions in aid of construction. The cost of repairs and maintenance, including planned generation overhauls, are expensed to Operations and Maintenance Expense on the Consolidated Statements of Income as costs are incurred. When TEP retires a unit of regulated property, accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no impact to the income statement. |
AFUDC and Capitalized Interest | AFUDC and Capitalized Interest AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense on the Consolidated Statements of Income. |
Depreciation | Depreciation Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 3 for additional information regarding utility plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the FERC. Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. |
Utility Plant Under Capital Leases | Utility Plant Under Capital Leases TEP finances a portion of the Springerville Common Facilities with capital leases. Capital lease expense is recorded in Amortization Expense and in Interest Expense—Capital Leases on the Consolidated Statements of Income. See Note 3 for additional information regarding utility plant and Note 6 for additional information related to the lease terms. |
Computer Software Costs | Computer Software Costs Costs incurred to purchase and develop internal use computer software are capitalized and amortized over the estimated economic life of the product. If the software is no longer useful or impaired, the carrying value is reduced and recorded as an expense on the income statement. |
Evaluation of Assets for Impairment | EVALUATION OF ASSETS FOR IMPAIRMENT Long-lived assets and investments are evaluated for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates. |
Deferred Financing Costs | DEFERRED FINANCING COSTS Using the effective interest method, costs to issue debt are deferred and amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. TEP accounts for debt issuance costs related to credit facility arrangements as an asset. The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt. |
Operating Revenues | OPERATING REVENUES Revenues related to the sale of energy are recognized when services or commodities are delivered to customers. The billing for the delivery of power to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates. Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events, if certain criteria are met. TEP charges customers the ACC-authorized tariff price plus separate ACC-authorized surcharges. TEP has identified its LFCR mechanism and DSM performance incentive as alternative revenues. 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. The LFCR surcharge is assessed as a percentage of the customer’s bill. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as the revenue is collected. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the 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, as approved in the 2017 Rate Order. In addition, the ACC approves a new DSM surcharge annually, which is effective June 1 of each year, to compensate TEP for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs are reflected in TEP’s non-fuel base rates as well as a performance incentive. TEP collects the DSM surcharge on a per kWh basis for residential customers and on a percentage of bill basis for non-residential customers. See Note 2 for additional information regarding regulatory matters. For purchased power and wholesale sales contracts that are settled financially, TEP nets the purchased power contracts with the sales contracts and reflects the amount in Wholesale Revenues on the Consolidated Statements of Income. TEP recognizes monthly management fees in Other Revenues on the Consolidated Statements of Income as the operator of Springerville Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of SRP. Additionally, Other Revenues includes reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and Springerville Coal Handling Facilities. The offsetting expenses are recorded in their respective line items on the income statement based on the nature of services provided. As the operating agent for Tri-State, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues on the Consolidated Statements of Income in the period earned. |
Purchased Power and Fuel Adjustment Clause | PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE TEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 2 for additional information regarding regulatory matters. |
Renewable Energy and Energy Efficiency Programs and Renewable Energy Credits | RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025 , with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved costs of carrying out this plan are recovered from retail customers through the RES surcharge. The associated lost revenues attributable to meeting DG targets will be partially recovered through the LFCR mechanism. 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 . The EE Standards require increasing annual targeted retail kWh savings equal to 22% by 2020 . Any RES or DSM surcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the balance sheet as a regulatory liability or asset. TEP recognizes RES and DSM surcharge revenue in Retail Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures. RENEWABLE ENERGY CREDITS The ACC measures compliance with the RES requirements through RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC mechanism. When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as other assets and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes purchased power expense and other revenues in an equal amount. TEP had $42 million and $24 million of RECs as of December 31, 2017 and 2016 , respectively. RECs are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets. See Note 2 for additional information regarding regulatory matters. |
Income Taxes | INCOME TAXES Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on the balance sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not some portion, or the entire deferred income tax asset, will not be realized. Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense on the Consolidated Statements of Income. TEP accounts for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as regulatory liabilities and amortized as a reduction in income tax expense over the tax life of the underlying asset. Income tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory asset. All other federal and state income tax credits are treated as a reduction to income tax expense in the year the credit arises. |
Fair Value | FAIR VALUE As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange. See Note 11 for additional information regarding fair value. |
Derivative Instruments | DERIVATIVE INSTRUMENTS The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to meet forecasted load and reserve requirements, to reduce exposure to energy commodity price volatility, and to hedge interest rate risk exposure. Derivative instruments that do not meet the normal purchase or normal sale scope exception will be recognized as either assets or liabilities on the balance sheet and are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not recorded at fair value and settled amounts are recognized as cost of fuel, energy, and capacity on the income statement. For derivatives designated as hedging contracts, TEP formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. Also, TEP formally documents hedging activity by transaction type and risk management strategy. For derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities. See Note 11 for additional information regarding derivative instruments. |
NATURE OF OPERATIONS AND SUMM24
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of New Accounting Pronouncements and Changes in Accounting Principles | On adoption, using the retrospective method of transition, TEP's Consolidated Statements of Cash Flows included the following adjustments: As Filed Adoption of ASU Impacts As Adjusted (in millions) Year Ended December 31, 2016 Net Cash Flows—Operating Activities $ 425 $ — $ 425 Net Cash Flows—Investing Activities (376 ) 3 (373 ) Net Cash Flows—Financing Activities (69 ) — (69 ) Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash (20 ) 3 (17 ) Cash, Cash Equivalents, and Restricted Cash, Beginning of Period 56 4 60 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 36 $ 7 $ 43 (in millions) Year Ended December 31, 2015 Net Cash Flows—Operating Activities $ 365 $ — $ 365 Net Cash Flows—Investing Activities (503 ) 2 (501 ) Net Cash Flows—Financing Activities 120 — 120 Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash (18 ) 2 (16 ) Cash, Cash Equivalents, and Restricted Cash, Beginning of Period 74 2 76 Cash, Cash Equivalents, and Restricted Cash, End of Period $ 56 $ 4 $ 60 |
Restrictions on Cash and 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: Years Ended December 31, (in millions) 2017 2016 2015 Cash and Cash Equivalents $ 38 $ 36 $ 56 Restricted Cash included in: Investments and Other Property 11 7 4 Current Assets, Other 1 — — Total Cash, Cash Equivalents, and Restricted Cash $ 50 $ 43 $ 60 |
Allowance For Doubtful Accounts | The change in the balance of the Allowance for Doubtful Accounts included in Accounts Receivable, Net on the Consolidated Balance Sheets is summarized as follows: Years Ended December 31, (in millions) 2017 2016 2015 Beginning of Period $ 5 $ 27 $ 5 Additions Charged to Cost and Expense 3 4 2 Write-offs (3 ) (3 ) (3 ) Provision for Springerville Unit 1, Third-Party Owners — (23 ) 23 End of Period $ 5 $ 5 $ 27 |
AFUDC Rates | The average AFUDC rates on regulated construction expenditures are included in the table below: 2017 2016 2015 Average AFUDC Rates 7.31 % 7.47 % 6.12 % |
Summary Of Average Annual Depreciation Rates For All Utility Plants | Below are the summarized average annual depreciation rates for all utility plant: 2017 2016 2015 Average Annual Depreciation Rates 2.97 % 2.85 % 2.83 % |
REGULATORY MATTERS (Tables)
REGULATORY MATTERS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Schedule of Purchased Power and Fuel Adjustment Rates | In February 2017, the ACC approved a PPFAC credit to begin returning the over-collected PPFAC bank balance to customers. The table below presents TEP's PPFAC rates approved by the ACC: Period Cents per kWh March 2017 through March 2018 (0.20 ) May 2016 through February 2017 0.15 April 2015 through April 2016 0.68 October 2014 through March 2015 0.50 |
Schedule of Regulatory Assets and Liabilities | in 2017 , $18 million in 2016 , and $12 million in 2015 . LFCR revenues are included in Retail Revenues on the Consolidated Statements of Income. REGULATORY ASSETS AND LIABILITIES Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below: Remaining Recovery Period (years) December 31, ($ in millions) 2017 2016 Regulatory Assets Pension and Other Postretirement Benefits (Note 8) Various $ 126 $ 128 Early Generation Retirement Costs (1) Various 84 — Income Taxes Recoverable through Future Rates (2) Various 40 29 Final Mine Reclamation and Retiree Healthcare Costs (3) 20 31 27 Lost Fixed Cost Recovery 1 29 23 Property Tax Deferrals (4) 1 24 23 Springerville Unit 1 Leasehold Improvements (5) 6 14 17 Sundt Coal Handling Facilities (6) N/A — 14 Other Regulatory Assets Various 40 20 Total Regulatory Assets 388 281 Less Current Portion 1 94 56 Total Non-Current Regulatory Assets $ 294 $ 225 Regulatory Liabilities Income Taxes Payable through Future Rates (2) Various $ 353 $ 3 Net Cost of Removal (7) Various 180 270 Renewable Energy Standard Various 44 32 Deferred Investment Tax Credits (8) Various 14 23 Purchased Power and Fuel Adjustment Clause 1 9 38 Other Regulatory Liabilities Various 5 11 Total Regulatory Liabilities 605 377 Less Current Portion 1 89 76 Total Non-Current Regulatory Liabilities $ 516 $ 301 (1) Includes the NBV and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Consolidated Balance Sheets due to the planned early retirement of the facilities. As of December 31, 2017 , Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. See Note 3 for additional information related to the planned early retirement of Navajo and Sundt Units 1 and 2. (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. See Note 1 and Note 12 for additional information regarding income taxes. (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 fully recover these costs through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2037 . (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 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 amortization period. (6) In June 2014, the EPA issued a final rule that required TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continued to use coal as a fuel source; or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. TEP applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. (7) Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. As a result of the 2017 Rate Order, $87 million was transferred from Net Cost of Removal to Accumulated Depreciation and Amortization to reflect the impact of the revised depreciation study on the estimated cost of removal. (8) Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset. |
UTILITY PLANT AND JOINTLY-OWN26
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Public Utility Property, Plant, and Equipment | The following table shows Plant in Service on the Consolidated Balance Sheets by major class: Annual Depreciation Rate (4) Average Remaining Life in Years (4) December 31, ($ in millions) 2017 2016 Plant in Service Generation Plant 3.19% 25 $ 2,548 $ 2,866 Transmission Plant 1.48% 32 1,001 1,024 Distribution Plant 1.56% 36 1,632 1,512 General Plant 5.89% 12 389 381 Intangible Plant, Software Costs, and Other (1) Various Various 207 185 Plant Held for Future Use — — 4 7 Total Plant in Service (2) $ 5,781 $ 5,975 Utility Plant Under Capital Leases (3) $ 85 $ 167 (1) Primarily represents computer software. Unamortized computer software costs were $59 million and $52 million as of December 31, 2017 and 2016 , respectively. The amortization of computer software costs was $19 million in 2017 , $17 million in 2016 , and $14 million in 2015 . Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and average remaining life of three years for large enterprise software. (2) Includes plant acquisition adjustments of $(134) million and $(139) million as of December 31, 2017 and 2016 , respectively. (3) In December 2017, TEP completed the purchase of an undivided ownership interest in the Springerville Common Facilities. See Note 6 for additional information regarding the Springerville leases. (4) Represents a composite of the depreciation rates of assets within each major class of utility plant and is based on the 2015 depreciation study available for the major classes of Plant in Service. TEP implemented new depreciation rates effective March 1, 2017, as approved in the 2017 Rate Order. |
Amount Of Lease Expense Incurred Related Capital Leases | The following table shows the amount of lease expense incurred for capital leases: Years Ended December 31, (in millions) 2017 2016 2015 Lease Expense Interest Expense included in: Interest Expense, Capital Leases $ 3 $ 3 $ 4 Amortization of Capital Lease Assets included in: Operating Expenses, Fuel — — 2 Operating Expenses, Amortization 6 5 6 Total Lease Expense $ 9 $ 8 $ 12 |
Schedule of Jointly Owned Utility Plants | As of December 31, 2017 , TEP was a participant in the following jointly-owned generation facilities and transmission systems: (in millions) Ownership Percentage Plant in Service Construction Work in Progress Accumulated Depreciation Net Book Value San Juan Unit 1 50.0% $ 274 $ 6 $ 83 $ 197 Four Corners Units 4 and 5 7.0% 113 54 79 88 Luna 33.3% 55 — 3 52 Gila River Unit 3 75.0% 203 3 60 146 Gila River Common Facilities 18.8% 25 — 8 17 Springerville Coal Handling Facilities 83.0% 202 — 81 121 Transmission Facilities Various 483 5 247 241 Total $ 1,355 $ 68 $ 561 $ 862 |
Schedule of Asset Retirement Obligations | The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Consolidated Balance Sheets: December 31, (in millions) 2017 2016 Beginning of Period $ 33 $ 32 Liabilities Incurred 3 — Liabilities Settled (1 ) — Regulatory Deferral/Accretion Expense 2 2 Revisions to the Present Value of Estimated Cash Flows (1) 9 (1 ) End of Period $ 46 $ 33 (1) Primarily related to changes in expected cost estimates and the acceleration of asset retirement dates of certain generation facilities. |
ACCOUNTS RECEIVABLE (Tables)
ACCOUNTS RECEIVABLE (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounts Receivable, Net [Abstract] | |
Accounts Receivable | The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets: December 31, (in millions) 2017 2016 Customer $ 81 $ 74 Due from Affiliates (Note 5) 7 9 Unbilled 39 34 Other 16 13 Allowance for Doubtful Accounts (5 ) (5 ) Accounts Receivable, Net $ 138 $ 125 |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Table) | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Schedule of Related Party Transactions | The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets: December 31, (in millions) 2017 2016 Receivables from Related Parties UNS Electric $ 5 $ 7 UNS Gas 2 2 Total Due from Related Parties $ 7 $ 9 Payables to Related Parties SES $ 3 $ 2 UNS Energy 1 — Total Due to Related Parties $ 4 $ 2 The following table presents the components of related party transactions included in the Consolidated Statements of Income: Years Ended December 31, (in millions) 2017 2016 2015 Goods and Services Provided by TEP to Affiliates Transmission Revenues, UNS Electric (1) $ 7 $ 7 $ 6 Wholesale Revenues, UNS Electric (1) — — 2 Control Area Services, UNS Electric (2) 3 2 2 Common Costs, UNS Energy Affiliates (3) 16 14 12 Corporate Services, Fortis Affiliates (4) 2 — — Goods and Services Provided by Affiliates to TEP Wholesale Revenues, UNS Electric (1) — 1 1 Supplemental Workforce, SES (5) 15 14 16 Corporate Services, UNS Energy (6) 5 7 7 Corporate Services, UNS Energy Affiliates (7) 5 4 1 (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) TEP provides non-tariffed goods and services to Fortis affiliate companies at the higher of fully burdened cost or fair market value. (5) 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. (6) 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 82% 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 $6 million in both 2017 and 2016 , and $5 million in 2015 . (7) Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible. |
DEBT, CREDIT FACILITY, AND CA29
DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of Long-term Debt Instruments | DEBT Long-term debt matures more than one year from the date of the financial statements. The following table presents the components of Long-Term Debt, Net on the Consolidated Balance Sheets: December 31, ($ in millions) Interest Rate Maturity Date 2017 2016 Notes 2011 Notes 5.15% 2021 $ 250 $ 250 2012 Notes 3.85% 2023 150 150 2014 Notes 5.00% 2044 150 150 2015 Notes 3.05% 2025 300 300 Tax-Exempt Local Furnishings Bonds 2010 Pima A 5.25% 2040 100 100 2012 Pima A 4.50% 2030 16 16 2013 Pima A 4.00% 2029 91 91 2013 Apache A (1) 1.41% 2032 100 100 Tax-Exempt Pollution Control Bonds 2009 Pima A 4.95% 2020 80 80 2009 Coconino A 5.13% 2032 15 15 2010 Coconino A (2) 1.76% 2032 37 37 2012 Apache A 4.50% 2030 177 177 Total Long-Term Debt (3) 1,466 1,466 Less Unamortized Discount and Debt Issuance Costs 12 13 Less Current Maturities of Long-Term Debt (1) 100 — Total Long-Term Debt, Net $ 1,354 $ 1,453 (1) The bonds are variable rate debt for which rates are reset monthly. The interest rate is calculated using a weighted average based on a percentage of an index equal to one-month LIBOR plus a credit spread. The bonds are subject to mandatory tender for purchase in November 2018, and were reclassified to Current Maturities of Long-Term Debt on the Consolidated Balance Sheets as of December 31, 2017 . (2) The bonds are variable rate debt for which rates are reset weekly. The interest rate is calculated using a weighted average and includes LOC fees and remarketing fees. The bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in February 2019. (3) As of December 31, 2017 , all of TEP's debt is unsecured, with the exception of the 2010 Coconino A variable rate bonds, which are backed by an LOC. |
Schedule of Capital Lease Obligations | CAPITAL LEASE OBLIGATIONS The following table details Capital Lease Obligations on the Consolidated Balance Sheets: December 31, (in millions) 2017 2016 Capital Lease Obligations $ 39 $ 91 Less Current Obligations Under Capital Leases 11 52 Total Capital Lease Obligations, Non-Current $ 28 $ 39 |
Schedule of Maturities of Long-term Debt | DEBT MATURITIES Long-term debt, including revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates: (in millions) Long-Term Debt (1) Capital Lease Obligations Total Debt Maturities (2) 2018 $ 100 $ 11 $ 111 2019 37 11 48 2020 80 18 98 2021 250 — 250 2022 — — — Total 2018 - 2022 467 40 507 Thereafter 999 — 999 Less: Imputed Interest — (1 ) (1 ) Total $ 1,466 $ 39 $ 1,505 (1) $37 million of TEP’s variable rate bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in February 2019. Although the variable rate bond matures in 2032, the above table reflects a redemption or repurchase of such bond in 2019 as though the LOC terminates without replacement upon expiration of the 2010 Reimbursement Agreement. TEP's 2013 tax-exempt variable rate IDRBs, which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in November 2018. (2) Total long-term debt excludes $10 million of related unamortized debt issuance costs and $2 million of unamortized original issue discount. |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments | As of December 31, 2017 , TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases: (in millions) 2018 2019 2020 2021 2022 Thereafter Total Fuel, Including Transportation $ 82 $ 83 $ 73 $ 43 $ 24 $ 244 $ 549 Purchased Power 29 — — — — — 29 Transmission 19 19 8 4 1 8 59 Renewable Power Purchase Agreements 64 64 63 63 63 668 985 RES Performance-Based Incentives 8 8 7 7 7 46 83 Operating Leases (1) 1 1 1 1 1 3 8 Land Easements and Rights-of-Way 1 1 1 2 2 82 89 Total Purchase Commitments $ 204 $ 176 $ 153 $ 120 $ 98 $ 1,051 $ 1,802 (1) Primarily represents leases for land, rail cars, and office facilities with varying terms, provisions, and expiration dates through 2036 . TEP's operating lease expense totaled $1 million in 2017 , $2 million in 2016 , and $3 million in 2015 . |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract] | |
Schedule of Amounts Recognized in Balance Sheet | The following table presents pension and other postretirement benefit amounts (excluding tax balances) included on the Consolidated Balance Sheets: Pension Benefits Other Postretirement Benefits December 31, (in millions) 2017 2016 2017 2016 Regulatory Assets $ 121 $ 123 $ 5 $ 5 Accrued Employee Expenses (1 ) (1 ) (2 ) (2 ) Pension and Other Postretirement Benefits (71 ) (69 ) (63 ) (63 ) Accumulated Other Comprehensive Loss, SERP 9 6 — — Net Amount Recognized $ 58 $ 59 $ (60 ) $ (60 ) |
Schedule of Changes in Funded Status | All plans have projected benefit obligations in excess of the fair value of plan assets for each period presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2017 2016 2017 2016 Change in Benefit Obligation Beginning of Period $ 424 $ 394 $ 79 $ 78 Actuarial Loss 42 20 1 — Interest Cost 15 15 2 2 Service Cost 13 12 4 4 Benefits Paid (19 ) (17 ) (4 ) (5 ) End of Period 475 424 82 79 Change in Fair Value of Plan Assets Beginning of Period 354 336 14 13 Actual Return on Plan Assets 59 27 2 1 Benefits Paid (19 ) (17 ) (4 ) (5 ) Employer Contributions (1) 9 8 5 5 End of Period 403 354 17 14 Funded Status at End of Period $ (72 ) $ (70 ) $ (65 ) $ (65 ) (1) TEP expects to contribute $11 million to the pension plans in 2018 . |
Schedule of Net Periodic Benefit Cost Not yet Recognized | The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2017 2016 2017 2016 Net Loss $ 129 $ 128 $ 5 $ 6 Prior Service Cost (Benefit) 1 — (1 ) (1 ) |
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets | The following table includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets: December 31, (in millions) 2017 2016 Accumulated Benefit Obligation $ 237 $ 384 Fair Value of Plan Assets 206 354 |
Components of Net Periodic Benefit Cost | Net periodic benefit plan cost includes the following components: Pension Benefits Other Postretirement Benefits Years Ended December 31, (in millions) 2017 2016 2015 2017 2016 2015 Service Cost $ 13 $ 12 $ 12 $ 4 $ 4 $ 4 Interest Cost 15 15 17 2 2 3 Expected Return on Plan Assets (25 ) (23 ) (23 ) (1 ) (1 ) (1 ) Amortization of Net Loss 8 7 7 — — — Net Periodic Benefit Cost $ 11 $ 11 $ 13 $ 5 $ 5 $ 6 Approximately 18% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income. |
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) | The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI were as follows: Pension Benefits Other Postretirement Benefits Regulatory Asset AOCI Regulatory Asset (in millions) 2017 2016 2015 2017 2016 2015 2017 2016 2015 Current Year Actuarial (Gain) Loss $ 5 $ 15 $ 5 $ 3 $ 1 $ — $ (1 ) $ — $ (4 ) Amortization of Net Loss (7 ) (7 ) (7 ) — — — — — — Total Recognized (Gain) Loss $ (2 ) $ 8 $ (2 ) $ 3 $ 1 $ — $ (1 ) $ — $ (4 ) |
Schedule of Expected Amortization of Prior Service Costs Charged to Net Period Benefit Cost | For all pension plans, TEP amortizes prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plans. Estimated amortization from regulatory assets into net periodic benefit cost in 2018 includes the following: (in millions) Pension Benefits Other Postretirement Benefits Net Loss $ 7 $ — |
Schedule Of Weighted Average Assumptions Used To Determine Benefit Obligations At Year End Table | The following table includes the weighted average assumptions used to determine benefit obligations: Pension Benefits Other Postretirement Benefits 2017 2016 2017 2016 Discount Rate 3.7% 4.2% 3.6% 4.0% Rate of Compensation Increase 2.8% 2.8% N/A N/A |
Schedule Of Weighted Average Assumptions Used To Determine Net Periodic Benefit Cost Table | The following table includes the weighted average assumptions used to determine net periodic benefit costs: Pension Benefits Other Postretirement Benefits 2017 2016 2015 2017 2016 2015 Discount Rate, Service Cost 4.4% 4.8% 4.2% 4.3% 4.6% 3.9% Discount Rate, Interest Cost 3.7% 3.9% 4.2% 3.3% 3.4% 3.9% Rate of Compensation Increase 2.8% 3.0% 3.0% N/A N/A N/A Expected Return on Plan Assets 7.0% 7.0% 7.0% 7.0% 7.0% 7.0% |
Schedule of Health Care Cost Trend Rates | Healthcare cost trend rates are assumed to decrease gradually from next year to the year the ultimate rate is reached: December 31, 2017 2016 Next Year 7.6% 7.6% Ultimate Rate Assumed 4.5% 4.5% Year Ultimate Rate is Reached 2036 2037 |
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates | Assumed healthcare cost trend rates significantly affect the amounts reported for healthcare plans. A one-percentage-point change in assumed healthcare cost trend rates would have the following effects on the amounts: One-Percentage- Point Increase One-Percentage- Point Decrease (in millions) December 31, 2017 Increase (Decrease) on Total Service and Interest Cost Components $ 1 $ (1 ) Increase (Decrease) on Other Postretirement Benefits Obligation 7 (6 ) |
Schedule of Allocation of Plan Assets | Asset allocations, by asset category, on the measurement date were as follows: Pension Other Postretirement Benefits 2017 2016 2017 2016 Asset Category Equity Securities 46 % 49 % 63 % 60 % Fixed Income Securities 45 % 41 % 35 % 35 % Real Estate 7 % 8 % — % 2 % Other 2 % 2 % 2 % 3 % Total 100 % 100 % 100 % 100 % |
FV Measurements of Pension Plan Assets by FV Hierarchy | The following tables present the fair value measurements of pension plan assets by level within the fair value hierarchy: Level 1 Level 2 Level 3 Total (in millions) December 31, 2017 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 66 — 66 United States Small Cap — 19 — 19 Non-United States — 72 — 72 Global — 30 — 30 Fixed Income — 179 — 179 Real Estate — 9 21 30 Private Equity — — 6 6 Total $ 1 $ 375 $ 27 $ 403 (in millions) December 31, 2016 Asset Category Cash Equivalents $ 1 $ — $ — $ 1 Equity Securities: United States Large Cap — 61 — 61 United States Small Cap — 18 — 18 Non-United States — 67 — 67 Global — 28 — 28 Fixed Income — 144 — 144 Real Estate — 9 19 28 Private Equity — — 7 7 Total $ 1 $ 327 $ 26 $ 354 • Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. • Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund. • Level 3 real estate investments values are generally determined by appraisals conducted in accordance with accepted appraisal guidelines, including consideration of projected income and expenses of the property as well as recent sales of similar properties. • Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models. |
Schedule of Reconciliation of Changes in Fair Value of Level 3 Plan Assets | The following table presents a reconciliation of changes in the fair value of pension plan assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. (in millions) Private Equity Real Estate Total Balance as of December 31, 2015 $ 7 $ 18 $ 25 Actual Return on Plan Assets: Assets Held at Reporting Date 1 1 2 Purchases, Sales, and Settlements (1 ) — (1 ) Balance as of December 31, 2016 7 19 26 Actual Return on Plan Assets: Assets Held at Reporting Date 1 2 3 Purchases, Sales, and Settlements (2 ) — (2 ) Balance as of December 31, 2017 $ 6 $ 21 $ 27 |
Target Allocation Percentages for Plan Assets | The current target allocation percentages for the major asset categories of the plan follow. Each plan allows a variance of +/- 2% from targets before funds are automatically rebalanced. Pension Other Postretirement Benefits December 31, 2017 Cash/Treasury Bills —% 2% Equity Securities: United States Large Cap 16% 39% United States Small Cap 5% 5% Non-United States Developed 14% 7% Non-United States Emerging 4% 9% Global Equity 4% —% Global Infrastructure 3% —% Fixed Income 45% 38% Real Estate 8% —% Private Equity 1% —% Total 100% 100% |
Schedule of Expected Benefit Payments | TEP expects the following benefit payments to be made by the plans, which reflect future service, as appropriate. (in millions) 2018 2019 2020 2021 2022 2023-2027 Pension Benefits $ 21 $ 22 $ 23 $ 24 $ 25 $ 137 Other Postretirement Benefits 5 5 5 6 6 30 |
SHARE-BASED COMPENSATION (Table
SHARE-BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award | The following table represents PSUs and RSUs awarded by UNS Energy: 2017 2016 2015 PSUs 68,126 66,974 47,776 RSUs 34,063 33,488 23,888 |
SUPPLEMENTAL CASH FLOW (Tables)
SUPPLEMENTAL CASH FLOW (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures | CASH TRANSACTIONS Years Ended December 31, (in millions) 2017 2016 2015 Interest, Net of Amounts Capitalized $ 61 $ 61 $ 65 Income Taxes (1) — — — (1) TEP did not pay federal or state income taxes due to net operating loss carryforwards offsetting taxable income. NON-CASH TRANSACTIONS Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows: Years Ended December 31, (in millions) 2017 2016 2015 Net Cost of Removal Increase (Decrease) (1) $ (88 ) $ 8 $ 1 Accrued Capital Expenditures 24 29 28 Commitment to Purchase Capital Lease Interests — 36 — Asset Retirement Obligations Increase (Decrease) (2) 10 (1 ) 3 (1) Represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In the 2017 Rate Order, the ACC authorized a new depreciation study for TEP modifying its depreciation reserves and rates. See Note 2 for additional information. (2) The non-cash additions to AROs and related capitalized assets represent a revision of estimated asset retirement cost due to changes in timing and amount of the expected future AROs. |
FAIR VALUE MEASUREMENTS AND D34
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Text Block [Abstract] | |
Financial Instruments Measured at Fair Value on a Recurring Basis | 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) December 31, 2017 Assets Cash Equivalents (1) $ 30 $ — $ — $ 30 Restricted Cash (1) 12 — — 12 Energy Derivative Contracts, Regulatory Recovery (2) — 9 — 9 Energy Derivative Contracts, No Regulatory Recovery (2) — — 3 3 Total Assets 42 9 3 54 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (26 ) — (26 ) Energy Derivative Contracts, No Regulatory Recovery (2) — — (1 ) (1 ) Interest Rate Swap (3) — (1 ) — (1 ) Total Liabilities — (27 ) (1 ) (28 ) Total Assets (Liabilities), Net $ 42 $ (18 ) $ 2 $ 26 (in millions) December 31, 2016 Assets Cash Equivalents (1) $ 23 $ — $ — $ 23 Restricted Cash (1) 7 — — 7 Energy Derivative Contracts, Regulatory Recovery (2) — 3 — 3 Energy Derivative Contracts, No Regulatory Recovery (2) — — 2 2 Total Assets 30 3 2 35 Liabilities Energy Derivative Contracts, Regulatory Recovery (2) — (2 ) (1 ) (3 ) Interest Rate Swap (3) — (2 ) — (2 ) Total Liabilities — (4 ) (1 ) (5 ) Total Assets (Liabilities), Net $ 30 $ (1 ) $ 1 $ 30 (1) Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Consolidated Balance Sheets. Restricted Cash is included in Investments and Other Property and in Current Assets—Other on the 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 Consolidated Balance Sheets. The valuation techniques are described below. (3) The Interest Rate Swap is valued using an income valuation approach based on the 6-month LIBOR and is included in Derivative Instruments on the Consolidated Balance Sheets. |
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) December 31, 2017 Derivative Assets Energy Derivative Contracts $ 12 $ 10 $ — $ 2 Derivative Liabilities Energy Derivative Contracts (27 ) (10 ) — (17 ) Interest Rate Swap (1 ) — — (1 ) (in millions) December 31, 2016 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (3 ) (2 ) — (1 ) Interest Rate Swap (2 ) — — (2 ) |
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) December 31, 2017 Derivative Assets Energy Derivative Contracts $ 12 $ 10 $ — $ 2 Derivative Liabilities Energy Derivative Contracts (27 ) (10 ) — (17 ) Interest Rate Swap (1 ) — — (1 ) (in millions) December 31, 2016 Derivative Assets Energy Derivative Contracts $ 5 $ 2 $ — $ 3 Derivative Liabilities Energy Derivative Contracts (3 ) (2 ) — (1 ) Interest Rate Swap (2 ) — — (2 ) |
Realized Losses from Cash Flow Hedges | Realized losses from cash flow hedges are shown in the following table: Years Ended December 31, (in millions) 2017 2016 2015 Capital Lease Interest Expense $ 1 $ 1 $ 2 Purchased Power — — 1 |
Financial Impact of Energy Contracts | Energy Derivative Contracts, Regulatory Recovery TEP records unrealized gains and losses on energy purchase contracts that are recoverable through the PPFAC mechanism on the balance sheet as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statement or in the statement of other comprehensive income, as shown in the following table: Years Ended December 31, (in millions) 2017 2016 2015 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ (18 ) $ 12 $ 6 |
Derivative Volumes | Derivative Volumes As of December 31, 2017 , TEP has energy contracts that will settle on various expiration dates through 2029 . The volumes associated with the energy contracts were as follows: December 31, 2017 2016 Power Contracts GWh 2,589 2,610 Gas Contracts BBtu (1) 137,952 12,355 (1) Increase in volume of gas contracts is a result of the planned early retirement of certain coal-fired generation. To reduce exposure to energy price risk associated with natural gas, the Company entered into longer term gas contracts increasing its overall volume outstanding in 2017. See Note 3 for additional information related to the planned early retirement of coal-fired generation. |
Fair Value Inputs, Assets, Quantitative Information Regarding Significant Unobservable Inputs | Level 3 Fair Value Measurements The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Fair Value of Range of Approach Assets Liabilities Unobservable Inputs Unobservable Input (in millions) December 31, 2017 Forward Power Contracts Market approach $ 3 $ (1 ) Market price per MWh $ 17.65 $ 34.60 (in millions) December 31, 2016 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 20.90 $ 40.00 |
Fair Value Inputs, Liabilities, Quantitative Information Regarding Significant Unobservable Inputs | Level 3 Fair Value Measurements The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Fair Value of Range of Approach Assets Liabilities Unobservable Inputs Unobservable Input (in millions) December 31, 2017 Forward Power Contracts Market approach $ 3 $ (1 ) Market price per MWh $ 17.65 $ 34.60 (in millions) December 31, 2016 Forward Power Contracts Market approach $ 2 $ (1 ) Market price per MWh $ 20.90 $ 40.00 |
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: Years Ended December 31, (in millions) 2017 2016 Beginning of Period $ 1 $ (2 ) Gains (Losses) Recorded Regulatory Assets or Liabilities, Derivative Instruments 1 2 Wholesale Revenues 4 4 Settlements (4 ) (3 ) End of Period $ 2 $ 1 Gains (Losses), Assets (Liabilities) still held $ 2 $ 1 |
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 December 31, (in millions) 2017 2016 2017 2016 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,466 $ 1,547 $ 1,472 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate | Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following: Years Ended December 31, (in millions) 2017 2016 2015 Federal Income Tax Expense at Statutory Rate $ 97 $ 64 $ 70 State Income Tax Expense, Net of Federal Deduction 9 6 8 Federal/State Tax Credits (9 ) (8 ) (8 ) Allowance for Equity Funds Used During Construction (2 ) (1 ) (1 ) Deferred Tax Asset Valuation Allowance — (2 ) 1 Impact of Enactment, TCJA 7 — — Other (1 ) — 2 Total Federal and State Income Tax Expense $ 101 $ 59 $ 72 |
Schedule Of Income Tax Reconciliation Table | Income tax expense included in the income statement consists of the following: Years Ended December 31, (in millions) 2017 2016 2015 Current Income Tax Expense Federal $ — $ — $ — State — — — Total Current Income Tax Expense — — — Deferred Income Tax Expense Federal 98 60 66 Federal Investment Tax Credits (6 ) (6 ) (6 ) State 9 5 12 Total Deferred Income Tax Expense 101 59 72 Total Federal and State Income Tax Expense $ 101 $ 59 $ 72 |
Schedule of Deferred Tax Assets and Liabilities | The significant components of deferred income tax assets and liabilities consist of the following: December 31, (in millions) 2017 2016 Gross Deferred Income Tax Assets Capital Lease Obligations $ 10 $ 35 Operating Loss Carryforwards, Net 56 129 Customer Advances and Contributions in Aid of Construction 14 20 Alternative Minimum Tax Credit 26 25 Other Postretirement Benefits 15 23 Emission Allowance Inventory 3 9 Investment Tax Credit Carryforward 34 32 Income Taxes Recoverable Through Future Rates 88 — Other 47 60 Total Gross Deferred Income Tax Assets 293 333 Deferred Tax Assets Valuation Allowance — — Gross Deferred Income Tax Liabilities Plant, Net (518 ) (774 ) Plant Abandonments (21 ) — Capital Lease Assets, Net (5 ) (24 ) Pensions (16 ) (26 ) Income Taxes Payable Through Future Rates (10 ) — Other (23 ) (38 ) Total Gross Deferred Income Tax Liabilities (593 ) (862 ) Deferred Income Taxes, Net $ (300 ) $ (529 ) |
Summary Of Details Of Tax Carryforwards Table | As of December 31, 2017 , TEP had the following carryforward amounts: (in millions) Amount Expiring Year Federal Net Operating Loss $ 263 2031-35 State Credits 8 2021-29 Alternative Minimum Tax Credit 26 None Investment Tax Credits 34 2031-37 |
Summary of Income Tax Contingencies | A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: December 31, (in millions) 2017 2016 Beginning of Period $ 12 $ 5 Additions Based on Tax Positions Taken in the Current Year 7 7 Reduction to Positions, TCJA (6 ) — End of Period $ 13 $ 12 |
QUARTERLY FINANCIAL DATA (UNAU
QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. First Quarter Second Quarter Third Quarter Fourth Quarter (in millions) 2017 Operating Revenue $ 268 $ 352 $ 417 $ 304 Operating Income 37 107 138 44 Net Income 21 61 82 13 2016 Operating Revenue $ 243 $ 317 $ 394 $ 281 Operating Income 12 72 122 37 Net Income (Loss) (1 ) 41 72 12 |
NATURE OF OPERATIONS AND SUMM37
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Additional Information) (Details) customer in Thousands, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017USD ($)mi²customer | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||
Retail customers | customer | 422 | |||
Area in which subsidiary generates transmits and distributes electricity to retail electric customers | mi² | 1,155 | |||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Cash and Cash Equivalents | $ 37,701 | $ 35,962 | $ 56,000 | |
Total Cash, Cash Equivalents, and Restricted Cash | 49,501 | 43,325 | 59,867 | $ 76,379 |
Investments and Other Property | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Total Cash, Cash Equivalents, and Restricted Cash | 11,000 | 7,000 | 4,000 | |
Current Assets, Other | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Total Cash, Cash Equivalents, and Restricted Cash | $ 1,000 | $ 0 | $ 0 | |
Lost Fixed Cost Recovery Mechanism | ||||
Restricted Cash and Cash Equivalents Items [Line Items] | ||||
Cap on increase in lost fixed cost recovery rate (in percentage) | 2.00% |
NATURE OF OPERATIONS AND SUMM38
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Recently Adopted Accounting Pronouncements) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Net Cash Flows—Operating Activities | $ 448,324 | $ 425,468 | $ 364,934 |
Net Cash Flows—Investing Activities | (391,813) | (372,877) | (500,917) |
Net Cash Flows—Financing Activities | (50,335) | (69,133) | 119,471 |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 6,176 | (16,542) | (16,512) |
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 43,325 | 59,867 | 76,379 |
Cash, Cash Equivalents, and Restricted Cash, End of Period | 37,701 | 35,962 | 56,000 |
New Accounting Pronouncement, Early Adoption, Effect | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Net Cash Flows—Operating Activities | 425,000 | 365,000 | |
Net Cash Flows—Investing Activities | (373,000) | (501,000) | |
Net Cash Flows—Financing Activities | (69,000) | 120,000 | |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | (17,000) | (16,000) | |
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 43,000 | 60,000 | 76,000 |
As Filed | New Accounting Pronouncement, Early Adoption, Effect | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Net Cash Flows—Operating Activities | 425,000 | 365,000 | |
Net Cash Flows—Investing Activities | (376,000) | (503,000) | |
Net Cash Flows—Financing Activities | (69,000) | 120,000 | |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | (20,000) | (18,000) | |
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | 36,000 | 56,000 | 74,000 |
Adoption of ASU Impacts | New Accounting Pronouncement, Early Adoption, Effect | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Net Cash Flows—Operating Activities | 0 | 0 | |
Net Cash Flows—Investing Activities | 3,000 | 2,000 | |
Net Cash Flows—Financing Activities | 0 | 0 | |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 3,000 | 2,000 | |
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period | $ 7,000 | $ 4,000 | $ 2,000 |
NATURE OF OPERATIONS AND SUMM39
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Allowance for Doubtful Accounts) (Details) - Allowance for Doubtful Accounts - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Beginning of Period | $ 5 | $ 27 | $ 5 |
Additions Charged to Cost and Expense | 3 | 4 | 2 |
Write-offs | (3) | (3) | (3) |
End of Period | 5 | 5 | 27 |
Springerville Unit 1 Third Party Owner Allegation | |||
Movement in Valuation Allowances and Reserves [Roll Forward] | |||
Provision for Springerville Unit 1, Third-Party Owners | $ 0 | $ (23) | $ 23 |
NATURE OF OPERATIONS AND SUMM40
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Average AFUDC Rates | 7.31% | 7.47% | 6.12% |
NATURE OF OPERATIONS AND SUMM41
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Average Annual Depreciation Rates for All Utility Plants) (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Average Annual Depreciation Rates | 2.97% | 2.85% | 2.83% |
NATURE OF OPERATIONS AND SUMM42
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy and Energy Efficiency Programs) (Details) | 12 Months Ended | ||
Dec. 31, 2025 | Dec. 31, 2020 | Dec. 31, 2017 | |
Renewable Energy Standard | |||
Public Utilities, General Disclosures [Line Items] | |||
Renewable energy target percentage by 2025 (in percentage) | 7.00% | ||
Scenario, Forecast | Renewable Energy Standard | |||
Public Utilities, General Disclosures [Line Items] | |||
Renewable energy target percentage by 2025 (in percentage) | 15.00% | ||
Distributed generation requirement target percentage (in percentage) | 30.00% | ||
Scenario, Forecast | Energy Efficiency Standards | |||
Public Utilities, General Disclosures [Line Items] | |||
Percentage of electric energy efficiency standards target retail savings on sales (in percentage) | 22.00% |
NATURE OF OPERATIONS AND SUMM43
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Renewable Energy Credits) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Renewable Energy Credits | $ 42 | $ 24 |
REGULATORY MATTERS (2017 Rate O
REGULATORY MATTERS (2017 Rate Order) (Details) - Arizona Corporation Commission - USD ($) $ in Millions | 1 Months Ended | |
Feb. 28, 2017 | Sep. 30, 2016 | |
Public Utilities, General Disclosures [Line Items] | ||
Approved Return on Original Cost Rate Base, Percentage | 7.04% | |
Approved Cost of Equity, Percentage | 9.75% | |
Approved Cost of Debt Component, Percentage | 4.32% | |
Non-fuel Component of Base Rate | ||
Public Utilities, General Disclosures [Line Items] | ||
Non-fuel base rate increase over adjusted test year revenues | $ 81.5 | |
Springerville Unit One | ||
Public Utilities, General Disclosures [Line Items] | ||
Purchased undivided interest in Springerville Unit 1 | 50.50% | |
Springerville Unit One | Non-fuel Component of Base Rate | ||
Public Utilities, General Disclosures [Line Items] | ||
Unit 1 Operating costs included in base rate increase | $ 15 |
REGULATORY MATTERS (Cost Recove
REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |||||
May 31, 2016USD ($) | Feb. 29, 2016USD ($) | Dec. 31, 2025 | Dec. 31, 2020 | Dec. 31, 2017USD ($)$ / kWh | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Purchased Power and Fuel Adjustment Clause | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Months approved rate in effect unless modified | 12 months | ||||||
Over-recovered costs for purchased power and fuel | $ 9 | $ 38 | |||||
Renewable Energy Standard | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Renewable energy target percentage (in percentage) | 7.00% | ||||||
Approved spending budget | $ 54 | ||||||
Recovery revenue | $ 1 | ||||||
Renewable energy actual percentage (in percentage) | 10.00% | ||||||
Renewable Energy Standard | Scenario, Forecast | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Renewable energy target percentage (in percentage) | 15.00% | ||||||
Distributed generation requirement target percentage (in percentage) | 30.00% | ||||||
Energy Efficiency Standards | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved spending budget | $ 22 | ||||||
Approved carryover of unused funds | 8 | ||||||
Approved Recovery of Spending Budget | 14 | ||||||
Renewable energy budget spending | $ 23 | ||||||
Percentage of cumulative annual retail kilowatt savings, actual (in percentage) | 14.00% | ||||||
Energy Efficiency Standards | Scenario, Forecast | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Percentage of electric energy efficiency standards target retail savings on sales (in percentage) | 22.00% | ||||||
Demand Side Management - Energy Efficiency Standards | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Recovery revenue | $ 2 | $ 3 | |||||
Lost Fixed Cost Recovery Mechanism | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Recovery revenue | $ 22 | $ 18 | $ 12 | ||||
Cap on increase in lost fixed cost recovery rate (in percentage) | 2.00% | ||||||
March 2017 through March 2018 | Purchased Power and Fuel Adjustment Clause | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Purchased power And fuel adjustment clause rate [cents per kwh] | $ / kWh | (0.0020) | ||||||
May 2016 through February 2017 | Purchased Power and Fuel Adjustment Clause | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Purchased power And fuel adjustment clause rate [cents per kwh] | $ / kWh | 0.0015 | ||||||
April 2015 through April 2016 | Purchased Power and Fuel Adjustment Clause | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Purchased power And fuel adjustment clause rate [cents per kwh] | $ / kWh | 0.0068 | ||||||
October 2014 through March 2015 | Purchased Power and Fuel Adjustment Clause | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Purchased power And fuel adjustment clause rate [cents per kwh] | $ / kWh | 0.0050 |
REGULATORY MATTERS (Regulatory
REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Regulatory Assets | $ 388,000 | $ 281,000 |
Regulatory Assets, Current | 93,960 | 56,340 |
Regulatory Assets, Noncurrent | 293,551 | 225,453 |
Pension and Other Postretirement Benefits (Note 8) | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets | 126,000 | 128,000 |
Early Generation Retirement Costs | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets | 84,000 | 0 |
Income Taxes Recoverable through Future Rates | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets | $ 40,000 | 29,000 |
Final Mine Reclamation and Retiree Health Care Costs | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 20 years | |
Regulatory Assets | $ 31,000 | 27,000 |
Lost Fixed Cost Recovery | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Regulatory Assets | $ 29,000 | 23,000 |
Property Tax Deferrals | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Regulatory Assets | $ 24,000 | 23,000 |
Springerville Unit 1 Leasehold Improvements | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 6 years | |
Regulatory Assets | $ 14,000 | 17,000 |
Sundt Coal Handling Facilities | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets | 0 | 14,000 |
Other Regulatory Assets | ||
Regulatory Assets [Line Items] | ||
Regulatory Assets | $ 40,000 | $ 20,000 |
REGULATORY MATTERS (Regulator47
REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Regulatory Liabilities [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Regulatory Liabilities | $ 605,000 | $ 377,000 |
Regulatory Liabilities, Current | 89,024 | 76,069 |
Regulatory Liabilities, Noncurrent | 516,438 | 300,700 |
Income Taxes Payable through Future Rates | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 353,000 | 3,000 |
Net Cost of Removal | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 180,000 | 270,000 |
Renewable Energy Standard | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 44,000 | 32,000 |
Deferred Investment Tax Credits | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | $ 14,000 | 23,000 |
Purchased Power and Fuel Adjustment Clause | ||
Regulatory Liabilities [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Regulatory Liabilities | $ 9,000 | 38,000 |
Other Regulatory Liabilities | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | $ 5,000 | $ 11,000 |
REGULATORY MATTERS (Regulator48
REGULATORY MATTERS (Regulatory Assets and liabilities- Footnotes) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Accumulated depreciation and amortization | $ 2,193,656 | $ 2,385,053 |
Property Tax Deferrals | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 1 year | |
Springerville Unit 1 Leasehold Improvements | ||
Regulatory Assets [Line Items] | ||
Remaining Recovery Period (years) | 6 years | |
Amortization period authorized to recover leasehold improvement costs at Springerville Unit 1 | 10 years | |
Net Cost of Removal | ||
Regulatory Assets [Line Items] | ||
Accumulated depreciation and amortization | $ 87,000 |
UTILITY PLANT AND JOINTLY-OWN49
UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Major Class) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 2.97% | 2.85% | 2.83% |
Plant in Service | $ 5,780,805 | $ 5,975,139 | |
Utility Plant under Capital Leases | 84,870 | 167,413 | |
Plant acquisition adjustments | $ (134,000) | (139,000) | |
Generation Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 3.19% | ||
Average Remaining Life in Years | 25 years | ||
Plant in Service | $ 2,548,000 | 2,866,000 | |
Transmission Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 1.48% | ||
Average Remaining Life in Years | 32 years | ||
Plant in Service | $ 1,001,000 | 1,024,000 | |
Distribution Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 1.56% | ||
Average Remaining Life in Years | 36 years | ||
Plant in Service | $ 1,632,000 | 1,512,000 | |
General Plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Annual Depreciation Rate | 5.89% | ||
Average Remaining Life in Years | 12 years | ||
Plant in Service | $ 389,000 | 381,000 | |
Intangible Plant, Software Costs and Other | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Plant in Service | 207,000 | 185,000 | |
Capitalized computer software, net | 59,000 | 52,000 | |
Amortization of computer software costs | 19,000 | 17,000 | $ 14,000 |
Plant Held for Future Use | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Plant in Service | $ 4,000 | $ 7,000 | |
Enterprise Software | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Average Remaining Life in Years | 3 years | ||
Minimum | Application Software | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Acquired finite-lived intangible assets, weighted average useful life (in years) | 3 years | ||
Maximum | Application Software | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Acquired finite-lived intangible assets, weighted average useful life (in years) | 5 years |
UTILITY PLANT AND JOINTLY-OWN50
UTILITY PLANT AND JOINTLY-OWNED FACILITES (Amount of Lease Expense Incurred for Generation-Related Capital Leases) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Capital Leases | $ 2,554 | $ 3,356 | $ 3,994 |
Total Lease Expense | 9,000 | 8,000 | 12,000 |
Interest Expense, Capital Leases | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Capital Leases | 3,000 | 3,000 | 4,000 |
Operating Expenses, Fuel | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Amortization of Capital Lease Assets | 0 | 0 | 2,000 |
Operating Expenses, Amortization | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Amortization of Capital Lease Assets | $ 6,000 | $ 5,000 | $ 6,000 |
UTILITY PLANT AND JOINTLY-OWN51
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Springerville Acquisition) (Details) - Springerville Unit One | Dec. 31, 2017 | Dec. 31, 2016 | Sep. 16, 2016 |
Unusual or Infrequent Item, or Both [Line Items] | |||
Percentage of ownership in generating units (in percentage) | 32.20% | 100.00% | |
Completion of Purchase of Equity Interest | |||
Unusual or Infrequent Item, or Both [Line Items] | |||
Percentage of ownership in generating units (in percentage) | 100.00% |
UTILITY PLANT AND JOINTLY-OWN52
UTILITY PLANT AND JOINTLY-OWNED FACILITES (Jointly-Owned Facilities) (Details) $ in Millions | Dec. 31, 2017USD ($) |
Public Utility, Property, Plant and Equipment [Line Items] | |
Plant in Service | $ 1,355 |
Construction Work in Progress | 68 |
Accumulated Depreciation | 561 |
Net Book Value | $ 862 |
San Juan Unit 1 | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 50.00% |
Plant in Service | $ 274 |
Construction Work in Progress | 6 |
Accumulated Depreciation | 83 |
Net Book Value | $ 197 |
Four Corners Units 4 and 5 | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 7.00% |
Plant in Service | $ 113 |
Construction Work in Progress | 54 |
Accumulated Depreciation | 79 |
Net Book Value | $ 88 |
Luna | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 33.30% |
Plant in Service | $ 55 |
Construction Work in Progress | 0 |
Accumulated Depreciation | 3 |
Net Book Value | $ 52 |
Gila River Unit 3 | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 75.00% |
Plant in Service | $ 203 |
Construction Work in Progress | 3 |
Accumulated Depreciation | 60 |
Net Book Value | $ 146 |
Gila River Common Facilities | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 18.80% |
Plant in Service | $ 25 |
Construction Work in Progress | 0 |
Accumulated Depreciation | 8 |
Net Book Value | $ 17 |
Springerville Coal Handling Facilities | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Ownership Percentage | 83.00% |
Plant in Service | $ 202 |
Construction Work in Progress | 0 |
Accumulated Depreciation | 81 |
Net Book Value | 121 |
Transmission Facilities | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Plant in Service | 483 |
Construction Work in Progress | 5 |
Accumulated Depreciation | 247 |
Net Book Value | $ 241 |
UTILITY PLANT AND JOINTLY-OWN53
UTILITY PLANT AND JOINTLY-OWNED FACILITIES UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Retirements) (Details) - USD ($) $ in Millions | 1 Months Ended | |||
Mar. 31, 2017 | Dec. 31, 2017 | Jun. 30, 2017 | Dec. 31, 2016 | |
Regulatory assets | $ 388 | $ 281 | ||
Generation Plant | San Juan Unit 2 | ||||
PPE, period increase (decrease) | $ (224) | |||
Retired Power Plant Costs | Navajo | ||||
Regulatory assets | $ 52 | |||
Retired Power Plant Costs | Sundt Coal Handling Facilities | ||||
Regulatory assets | $ 31 |
UTILITY PLANT AND JOINTLY-OWN54
UTILITY PLANT AND JOINTLY-OWNED FACILITES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning of Period | $ 33 | $ 32 |
Liabilities Incurred | 3 | 0 |
Liabilities Settled | (1) | 0 |
Regulatory Deferral/Accretion Expense | 2 | 2 |
Revisions to the Present Value of Estimated Cash Flows | 9 | (1) |
End of Period | $ 46 | $ 33 |
ACCOUNTS RECEIVABLE (Details)
ACCOUNTS RECEIVABLE (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Allowance for Doubtful Accounts | $ (5,000) | $ (5,000) |
Accounts Receivable, Net | 137,932 | 124,934 |
Customer | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Gross | 81,000 | 74,000 |
Customer | Unbilled | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Gross | 39,000 | 34,000 |
Customer | Due from Affiliates (Note 5) | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Gross | 7,000 | 9,000 |
Other | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts Receivable, Gross | $ 16,000 | $ 13,000 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Receivables from Related Parties | $ 7,000 | $ 9,000 | |
Payables to Related Parties | 4,000 | 2,000 | |
Contribution from Parent | 0 | 0 | $ 180,000 |
Dividends Declared to Parent | (70,000) | (50,000) | (50,000) |
Transmission Revenues, UNS Electric | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Transmission and Wholesale Revenue | 7,000 | 7,000 | 6,000 |
Wholesale Revenues, UNS Electric | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Transmission and Wholesale Revenue | 0 | 0 | 2,000 |
Control Area Services, UNS Electric | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Control Area Services, UNS Electric | 3,000 | 2,000 | 2,000 |
Common Costs, UNS Energy Affiliates | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Common Costs, UNS Energy Affiliates | 16,000 | 14,000 | 12,000 |
Corporate Services, Fortis Affiliates | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Transmission and Wholesale Revenue | 2,000 | 0 | 0 |
Wholesale Revenues, UNS Electric | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Wholesale Revenues, UNS Electric | 0 | 1,000 | 1,000 |
Supplemental Workforce, SES | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Supplemental Workforce, SES | 15,000 | 14,000 | 16,000 |
Corporate Services, UNS Energy | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Corporate Services | $ 5,000 | 7,000 | 7,000 |
Intercompany allocation parent to subsidiary (in percentage) | 82.00% | ||
Management fee | $ 6,000 | 6,000 | 5,000 |
Corporate Services, UNS Energy Affiliates | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Corporate Services | 5,000 | 4,000 | $ 1,000 |
UNS Electric | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Receivables from Related Parties | 5,000 | 7,000 | |
UNS Gas | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Receivables from Related Parties | 2,000 | 2,000 | |
SES | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Payables to Related Parties | 3,000 | 2,000 | |
UNS Energy | |||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||
Payables to Related Parties | $ 1,000 | $ 0 |
DEBT, CREDIT FACILITY, AND CA57
DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Long-term Debt) (Detail) - USD ($) | 1 Months Ended | ||||
Aug. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Feb. 28, 2015 | Jan. 31, 2015 | |
Debt Instrument [Line Items] | |||||
Total Long-Term Debt | $ 1,466,000,000 | $ 1,466,000,000 | |||
Less Unamortized Discount and Debt Issuance Costs | 12,000,000 | 13,000,000 | |||
Current Maturities of Long-Term Debt | 100,000,000 | 0 | |||
Total Long-Term Debt, Net | $ 1,354,423,000 | 1,453,072,000 | |||
Notes 2011 5.15% due 2021 | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Interest Rate (in percentage) | 5.15% | ||||
Total Long-Term Debt | $ 250,000,000 | 250,000,000 | |||
Notes 2012 3.85% due 2023 | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Interest Rate (in percentage) | 3.85% | ||||
Total Long-Term Debt | $ 150,000,000 | 150,000,000 | |||
Notes 2014 5.00% due 2044 | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Interest Rate (in percentage) | 5.00% | ||||
Total Long-Term Debt | $ 150,000,000 | 150,000,000 | |||
Notes 2015 3.05% due 2025 | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Interest Rate (in percentage) | 3.05% | ||||
Total Long-Term Debt | $ 300,000,000 | 300,000,000 | |||
Debt instrument, face amount | $ 300,000,000 | ||||
Tax Exempt Local Furnishings Bonds 2010 Pima A due 2040 5.25% | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Interest Rate (in percentage) | 5.25% | ||||
Total Long-Term Debt | $ 100,000,000 | 100,000,000 | |||
Tax Exempt Local Furnishings Bonds 2012 Pima A due 2030 4.50% | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Interest Rate (in percentage) | 4.50% | ||||
Total Long-Term Debt | $ 16,000,000 | 16,000,000 | |||
Tax Exempt Local Furnishings Bonds 2013 Pima A due 2029 4.00% | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Interest Rate (in percentage) | 4.00% | ||||
Total Long-Term Debt | $ 91,000,000 | 91,000,000 | |||
Tax Exempt Local Furnishings Bonds 2013 Apache A due 2032 Variable Rate | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Effective interest rate (in percentage) | 1.41% | ||||
Total Long-Term Debt | $ 100,000,000 | 100,000,000 | |||
Debt instrument, face amount | $ 100,000,000 | ||||
Tax Exempt Pollution Control Bonds 2009 Pima A due 2020 4.95% | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Interest Rate (in percentage) | 4.95% | ||||
Total Long-Term Debt | $ 80,000,000 | 80,000,000 | |||
Tax Exempt Pollution Control Bonds 2009 Coconino A due 2032 5.13% | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Interest Rate (in percentage) | 5.13% | ||||
Total Long-Term Debt | $ 15,000,000 | 15,000,000 | |||
Tax Exempt Pollution Control Bonds 2010 Coconino A due 2032 Variable Rate | Secured Debt | |||||
Debt Instrument [Line Items] | |||||
Effective interest rate (in percentage) | 1.76% | ||||
Total Long-Term Debt | $ 37,000,000 | 37,000,000 | |||
Debt instrument, face amount | $ 37,000,000 | ||||
Tax Exempt Pollution Control Bonds 2012 Apache A due 2030 4.50% | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Interest Rate (in percentage) | 4.50% | ||||
Total Long-Term Debt | $ 177,000,000 | $ 177,000,000 | |||
Tax Exempt Local Furnishings Bonds 2008 Pima B 5.75% due 2029 | Unsecured Debt | |||||
Debt Instrument [Line Items] | |||||
Debt instrument, repurchased face amount | $ 130,000,000 | ||||
Tax Exempt Variable Rate | Secured Debt | |||||
Debt Instrument [Line Items] | |||||
Debt extinguishment | $ 79,000,000 |
DEBT, CREDIT FACILITY, AND CA58
DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Credit Facility) (Details) | 1 Months Ended | 12 Months Ended | ||
Oct. 31, 2015USD ($)credit_extension | Dec. 31, 2017USD ($) | Feb. 15, 2017USD ($) | Dec. 31, 2010USD ($) | |
Line of Credit | Revolving Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Line of credit facility borrowing capacity | $ 250,000,000 | |||
Line of credit facility, number of extensions Allowed | credit_extension | 2 | |||
Line of credit facility, extension period (in years) | 1 year | |||
Interest rate spread on LIBOR borrowing (in percentage) | 1.00% | |||
Interest rate in addition to alternate base rate for alternate base rate loans | 0.00% | |||
Line of credit facility, fair value of amount outstanding | $ 35,000,000 | |||
Remaining borrowing capacity | $ 232,000,000 | |||
Line of Credit | Revolving Credit Facility LOC Sublimit | ||||
Debt Instrument [Line Items] | ||||
Line of credit facility borrowing capacity | $ 50,000,000 | |||
Line of Credit | Revolving Credit Facility 2014 and 2010 | ||||
Debt Instrument [Line Items] | ||||
Line of credit facility borrowing capacity | 270,000,000 | |||
Line of Credit | Term Loan | ||||
Debt Instrument [Line Items] | ||||
Line of credit facility borrowing capacity | $ 130,000,000 | |||
Letter of Credit | ||||
Debt Instrument [Line Items] | ||||
Letter of credit, issued in support of tax exempt bonds | $ 37,000,000 | |||
Letter of credit, interest rate (in percentage) | 0.75% |
DEBT, CREDIT FACILITY, AND CA59
DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Capital Lease) (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Apr. 30, 2015USD ($) | Dec. 31, 2017USD ($)lease | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 16, 2016 | Jan. 31, 2016MW | May 31, 2015USD ($) | Jan. 31, 2015USD ($)MW | |
Debt Instrument [Line Items] | ||||||||||
Capital Lease Obligations | $ 91,000 | $ 39,000 | $ 91,000 | |||||||
Less Current Obligations Under Capital Leases | 51,765 | 10,749 | 51,765 | |||||||
Total Capital Lease Obligations, Non-Current | 39,267 | $ 28,519 | 39,267 | |||||||
Lessee, Operating Lease, Renewal Term | 2 years | |||||||||
Payments to Acquire Equipment on Lease | $ 0 | 0 | $ 120,312 | |||||||
Fixed purchase price | 0 | $ 36,000 | $ 0 | |||||||
Interest Rate Swap | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Notional amount | $ 18,000 | |||||||||
Springerville Common Facilities Lease Debt | Interest Rate Swap | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Fixed rate of interest related to interest rate swap | 5.77% | |||||||||
Notional amount | $ 18,000 | |||||||||
Notional amount of debt | $ 3,000 | |||||||||
Derivative basis spread | 1.88% | 1.88% | 1.88% | |||||||
Springerville Common Facility Lease Expiring January 2021 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Number of operating lease | lease | 2 | |||||||||
Percentage of interest committed to purchase | 14.00% | |||||||||
Springerville Common Facilities | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Jointly Owned, Percentage of Interest Purchased | 17.80% | |||||||||
Fixed purchase price | $ 68,000 | |||||||||
Springerville Common Facilities | Springerville Common Facility Lease Expiring December 2017 | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Increase (Decrease) in Capital Lease Obligation | 36,000 | |||||||||
Payments to Acquire Equipment on Lease | $ 38,000 | |||||||||
Springerville Unit One | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of ownership in generating units (in percentage) | 100.00% | 32.20% | 100.00% | |||||||
Springerville Unit One | Additional Purchase of Equity Interest | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of ownership in generating station | 24.80% | |||||||||
Generating capacity purchased, in MWs | MW | 96 | |||||||||
Springerville Unit One | Completion of Purchase of Equity Interest | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of ownership in generating station | 49.50% | |||||||||
Generating capacity purchased, in MWs | MW | 387 | 192 | ||||||||
Percentage of ownership in generating units (in percentage) | 100.00% | |||||||||
Fixed price to acquire leased interest in facilities | $ 85,000 | |||||||||
Springerville Unit One | Springerville Unit One Lease | Additional Purchase of Equity Interest | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Lease arrangement, fair market value purchase price | $ 46,000 | |||||||||
Springerville Coal Handling Facilities | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of ownership in generating station | 83.00% | |||||||||
Springerville Coal Handling Facilities | SRP | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of ownership in generating station | 17.05% | |||||||||
Springerville Coal Handling Facilities | Additional Purchase of Equity Interest | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of ownership in generating station | 86.70% | 67.80% | ||||||||
Springerville Coal Handling Facilities | Completion of Purchase of Equity Interest | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Percentage of ownership in generating units (in percentage) | 100.00% | |||||||||
Springerville Coal Handling Facilities | Springerville Coal Handling Facilities Lease | SRP | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Sales price of leased interest in facilities | $ 24,000 | |||||||||
Springerville Coal Handling Facilities | Springerville Coal Handling Facilities Lease | Additional Purchase of Equity Interest | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Fixed price to acquire leased interest in facilities | $ 120,000 |
DEBT, CREDIT FACILITY, AND CA60
DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt) (Detail) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Long-Term Debt Maturities | ||
2,018 | $ 100 | |
2,019 | 37 | |
2,020 | 80 | |
2,021 | 250 | |
2,022 | 0 | |
Total 2018 - 2022 | 467 | |
Thereafter | 999 | |
Less: Imputed Interest | 0 | |
Total Long-Term Debt | 1,466 | $ 1,466 |
Capital Lease Obligations | ||
2,018 | 11 | |
2,019 | 11 | |
2,020 | 18 | |
2,021 | 0 | |
2,022 | 0 | |
Total 2018 - 2022 | 40 | |
Thereafter | 0 | |
Less: Imputed Interest | (1) | |
Capital Lease Obligations | 39 | $ 91 |
2,018 | 111 | |
2,019 | 48 | |
2,020 | 98 | |
2,021 | 250 | |
2,022 | 0 | |
Total 2018 - 2022 | 507 | |
Thereafter | 999 | |
Less: Imputed Interest | (1) | |
Total LT Debt and Capital Lease Obligations | $ 1,505 |
DEBT, CREDIT FACILITY, AND CA61
DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt Footnotes) (Detail) | Dec. 31, 2017USD ($) |
Schedule Of Maturities Of Long Term Debt [Line Items] | |
Unamortized debt issuance expense | $ 10,000,000 |
Debt discount | 2,000,000 |
Tax Exempt Pollution Control Bonds 2010 Coconino A due 2032 Variable Rate | Secured Debt | |
Schedule Of Maturities Of Long Term Debt [Line Items] | |
Debt instrument, face amount | 37,000,000 |
Tax Exempt Local Furnishings Bonds 2013 Apache A due 2032 Variable Rate | Unsecured Debt | |
Schedule Of Maturities Of Long Term Debt [Line Items] | |
Debt instrument, face amount | $ 100,000,000 |
COMMITMENTS AND CONTINGENCIES62
COMMITMENTS AND CONTINGENCIES (COMMITMENTS) (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017USD ($)rental_payment_option | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Jan. 31, 2018USD ($) | |
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Unrecorded Unconditional Purchase Obligation, Number of Different Rental Payments | rental_payment_option | 5 | |||
Unrecorded Unconditional Purchase Obligation, Ownership Percentage | 7.50% | |||
2,018 | $ 204 | |||
2,019 | 176 | |||
2,020 | 153 | |||
2,021 | 120 | |||
2,022 | 98 | |||
Thereafter | 1,051 | |||
Total | 1,802 | |||
Rent expense | 1 | $ 2 | $ 3 | |
Fuel, Including Transportation | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2,018 | 82 | |||
2,019 | 83 | |||
2,020 | 73 | |||
2,021 | 43 | |||
2,022 | 24 | |||
Thereafter | 244 | |||
Total | 549 | |||
Purchased Power | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2,018 | 29 | |||
2,019 | 0 | |||
2,020 | 0 | |||
2,021 | 0 | |||
2,022 | 0 | |||
Thereafter | 0 | |||
Total | 29 | |||
Transmission | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2,018 | 19 | |||
2,019 | 19 | |||
2,020 | 8 | |||
2,021 | 4 | |||
2,022 | 1 | |||
Thereafter | 8 | |||
Total | 59 | |||
Renewable Power Purchase Agreements | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2,018 | 64 | |||
2,019 | 64 | |||
2,020 | 63 | |||
2,021 | 63 | |||
2,022 | 63 | |||
Thereafter | $ 668 | |||
Percentage of Purchase Power Obligations | 100.00% | |||
Total | $ 985 | |||
RES Performance-Based Incentives | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2,018 | 8 | |||
2,019 | 8 | |||
2,020 | 7 | |||
2,021 | 7 | |||
2,022 | 7 | |||
Thereafter | 46 | |||
Total | 83 | |||
Operating Leases | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2,018 | 1 | |||
2,019 | 1 | |||
2,020 | 1 | |||
2,021 | 1 | |||
2,022 | 1 | |||
Thereafter | 3 | |||
Total | 8 | |||
Land Easements and Rights-of-Way | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2,018 | 1 | |||
2,019 | 1 | |||
2,020 | 1 | |||
2,021 | 2 | |||
2,022 | 2 | |||
Thereafter | 82 | |||
Total | 89 | |||
Subsequent Event | Fuel, Including Transportation | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2,018 | $ 4 | |||
2,019 | 5 | |||
2,020 | 5 | |||
2,021 | 5 | |||
2,022 | 5 | |||
Thereafter | $ 1 | |||
Maximum | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Total | 8 | |||
Minimum | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
Total | $ 3 |
COMMITMENTS AND CONTINGENCIES63
COMMITMENTS AND CONTINGENCIES (CONTINGENCIES) (Detail) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||||
May 30, 2017 | Jan. 31, 2017 | Sep. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commitments And Contingencies [Line Items] | ||||||
Payments to Acquire Other Productive Assets | $ 0 | $ 85,000 | $ 45,753 | |||
Loss Contingency, Accrual, Reversal | $ 5,000 | |||||
Springerville Unit 1 Third Party Owner Allegation | Settled Litigation | ||||||
Commitments And Contingencies [Line Items] | ||||||
Payments to Acquire Other Productive Assets | $ 85,000 | |||||
Proceeds from Legal Settlements | $ 12,500 | |||||
FERC Refund Orders | ||||||
Commitments And Contingencies [Line Items] | ||||||
Litigation settlement, amount awarded from other party | $ 8,000 | |||||
FERC Refund Orders | Wholesale Revenue | ||||||
Commitments And Contingencies [Line Items] | ||||||
Loss Contingency Accrual, Provision | 22,000 | |||||
FERC Refund Orders | Other Current Liabilities | ||||||
Commitments And Contingencies [Line Items] | ||||||
Loss Contingency Accrual | 5,000 | |||||
Navajo, San Juan, Four Corners | ||||||
Commitments And Contingencies [Line Items] | ||||||
Share of Reclamation Costs Anticipated | 61,000 | |||||
Navajo, San Juan, Four Corners | Other Liabilities | ||||||
Commitments And Contingencies [Line Items] | ||||||
Environmental Exit Costs, Costs Accrued to Date | $ 34,000 | $ 26,000 |
COMMITMENTS AND CONTINGENCIES64
COMMITMENTS AND CONTINGENCIES (PERFORMANCE GUARANTEES) (Detail) - Performance Guarantee | Dec. 31, 2017USD ($) |
Guarantor Obligations [Line Items] | |
Current carrying value | $ 0 |
Four Corner | |
Guarantor Obligations [Line Items] | |
Maximum exposure, undiscounted | 250,000,000 |
Navajo, San Juan, Luna | |
Guarantor Obligations [Line Items] | |
Maximum exposure, undiscounted | $ 0 |
EMPLOYEE BENEFIT PLANS (Pension
EMPLOYEE BENEFIT PLANS (Pension and Other Postretirement Benefit Amounts included in Consolidated Balance Sheet ) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Assets | $ 388 | $ 281 |
Pension Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Assets | 121 | 123 |
Accrued Employee Expenses | (1) | (1) |
Pension and Other Postretirement Benefits | (71) | (69) |
Accumulated Other Comprehensive Loss, SERP | 9 | 6 |
Net Amount Recognized | 58 | 59 |
Other Postretirement Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Assets | 5 | 5 |
Accrued Employee Expenses | (2) | (2) |
Pension and Other Postretirement Benefits | (63) | (63) |
Accumulated Other Comprehensive Loss, SERP | 0 | 0 |
Net Amount Recognized | $ (60) | $ (60) |
EMPLOYEE BENEFIT PLANS (Change
EMPLOYEE BENEFIT PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Benefits | |||
Change in Projected Benefit Obligation | |||
Beginning of Period | $ 424 | $ 394 | |
Actuarial Loss | 42 | 20 | |
Interest Cost | 15 | 15 | $ 17 |
Service Cost | 13 | 12 | 12 |
Benefits Paid | (19) | (17) | |
End of Period | 475 | 424 | 394 |
Change in Fair Value of Plan Assets | |||
Beginning of Period | 354 | 336 | |
Actual Return on Plan Assets | 59 | 27 | |
Benefits Paid | (19) | (17) | |
Employer Contributions | 9 | 8 | |
End of Period | 403 | 354 | 336 |
Funded Status at End of Period | (72) | (70) | |
Other Postretirement Benefits | |||
Change in Projected Benefit Obligation | |||
Beginning of Period | 79 | 78 | |
Actuarial Loss | 1 | 0 | |
Interest Cost | 2 | 2 | 3 |
Service Cost | 4 | 4 | 4 |
Benefits Paid | (4) | (5) | |
End of Period | 82 | 79 | 78 |
Change in Fair Value of Plan Assets | |||
Beginning of Period | 14 | 13 | |
Actual Return on Plan Assets | 2 | 1 | |
Benefits Paid | (4) | (5) | |
Employer Contributions | 5 | 5 | |
End of Period | 17 | 14 | $ 13 |
Funded Status at End of Period | $ (65) | $ (65) |
EMPLOYEE BENEFIT PLANS (Expecte
EMPLOYEE BENEFIT PLANS (Expected Pension Contributions For Next Year) (Details) $ in Millions | Dec. 31, 2017USD ($) |
Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year | $ 11 |
EMPLOYEE BENEFIT PLANS (Compone
EMPLOYEE BENEFIT PLANS (Components of Regulatory Assets and Accumulated Other Comprehensive Loss Not Recognized as Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Net Loss | $ 129 | $ 128 |
Prior Service Cost (Benefit) | 1 | 0 |
Other Postretirement Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Net Loss | 5 | 6 |
Prior Service Cost (Benefit) | $ (1) | $ (1) |
EMPLOYEE BENEFIT PLANS (Informa
EMPLOYEE BENEFIT PLANS (Information for Pension Plans with Accumulated Benefit Obligations in Excess of Pension Plan Assets) (Details) $ in Millions | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)plan |
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items] | ||
Number of Defined Benefit Pension Plans with ABO in Excess of Plan Assets | plan | 3 | |
Pension Benefits | ||
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items] | ||
Accumulated Benefit Obligation | $ 237 | $ 384 |
Fair Value of Plan Assets | $ 206 | $ 354 |
EMPLOYEE BENEFIT PLANS (Compo70
EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | $ 13 | $ 12 | $ 12 |
Interest Cost | 15 | 15 | 17 |
Expected Return on Plan Assets | (25) | (23) | (23) |
Amortization of Net Loss | 8 | 7 | 7 |
Net Periodic Benefit Cost | 11 | 11 | 13 |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | 4 | 4 | 4 |
Interest Cost | 2 | 2 | 3 |
Expected Return on Plan Assets | (1) | (1) | (1) |
Amortization of Net Loss | 0 | 0 | 0 |
Net Periodic Benefit Cost | $ 5 | $ 5 | $ 6 |
EMPLOYEE BENEFIT PLANS (Changes
EMPLOYEE BENEFIT PLANS (Changes in Regulatory Assets and Accumulated Comprehensive Income) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Benefits | Regulatory Asset | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Current Year Actuarial (Gain) Loss | $ 5 | $ 15 | $ 5 |
Amortization of Net Loss | (7) | (7) | (7) |
Total Recognized (Gain) Loss | (2) | 8 | (2) |
Pension Benefits | Accumulated Other Comprehensive Loss | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Current Year Actuarial (Gain) Loss | 3 | 1 | 0 |
Amortization of Net Loss | 0 | 0 | 0 |
Total Recognized (Gain) Loss | 3 | 1 | 0 |
Other Postretirement Benefits | Regulatory Asset | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Current Year Actuarial (Gain) Loss | (1) | 0 | (4) |
Amortization of Net Loss | 0 | 0 | 0 |
Total Recognized (Gain) Loss | $ (1) | $ 0 | $ (4) |
EMPLOYEE BENEFIT PLANS (Future
EMPLOYEE BENEFIT PLANS (Future Amortization) (Details) - Regulatory Asset $ in Millions | Dec. 31, 2017USD ($) |
Pension Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Net Loss | $ 7 |
Other Postretirement Benefits | |
Defined Benefit Plan Disclosure [Line Items] | |
Net Loss | $ 0 |
EMPLOYEE BENEFIT PLANS (Weighte
EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Details) | Dec. 31, 2017 | Dec. 31, 2016 |
Pension Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount Rate (in percentage) | 3.70% | 4.20% |
Rate of Compensation Increase (in percentage) | 2.80% | 2.80% |
Other Postretirement Benefits | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount Rate (in percentage) | 3.60% | 4.00% |
EMPLOYEE BENEFIT PLANS (Weigh74
EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Rate of Compensation Increase (in percentage) | 2.80% | 3.00% | 3.00% |
Expected Return on Plan Assets | 7.00% | 7.00% | 7.00% |
Pension Benefits | Service cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate (in percentage) | 4.40% | 4.80% | 4.20% |
Pension Benefits | Interest Cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate (in percentage) | 3.70% | 3.90% | 4.20% |
Other Postretirement Benefits | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Expected Return on Plan Assets | 7.00% | 7.00% | 7.00% |
Other Postretirement Benefits | Service cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate (in percentage) | 4.30% | 4.60% | 3.90% |
Other Postretirement Benefits | Interest Cost | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate (in percentage) | 3.30% | 3.40% | 3.90% |
EMPLOYEE BENEFIT PLANS(Assumed
EMPLOYEE BENEFIT PLANS(Assumed Health Care Cost Trend Rates) (Details) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract] | ||
Next Year | 7.60% | 7.60% |
Ultimate Rate Assumed | 4.50% | 4.50% |
Year Ultimate Rate is Reached | 2,036 | 2,037 |
EMPLOYEE BENEFIT PLANS (One-Per
EMPLOYEE BENEFIT PLANS (One-Percentage-Point Change in Assumed Health Care Cost Trend Rates) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract] | |
Effect of one percentage point increase on service and interest cost components | $ 1 |
Effect of one percentage point decrease on service and interest cost components | (1) |
Effect on Retiree Benefit Obligation, One-Percentage-Point Increase | 7 |
Effect on Retiree Benefit Obligation, One-Percentage-Point Decrease | $ (6) |
EMPLOYEE BENEFIT PLANS (Percent
EMPLOYEE BENEFIT PLANS (Percentage of Pension Plan Assets By Asset Category) (Details) | Dec. 31, 2017 | Dec. 31, 2016 |
Pension Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 100.00% | 100.00% |
Pension Benefits | Equity Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 46.00% | 49.00% |
Pension Benefits | Fixed Income Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 45.00% | 41.00% |
Pension Benefits | Real Estate | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 7.00% | 8.00% |
Pension Benefits | Other | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 2.00% | 2.00% |
Other Postretirement Benefits | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 100.00% | 100.00% |
Other Postretirement Benefits | Equity Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 63.00% | 60.00% |
Other Postretirement Benefits | Fixed Income Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 35.00% | 35.00% |
Other Postretirement Benefits | Real Estate | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 0.00% | 2.00% |
Other Postretirement Benefits | Other | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 2.00% | 3.00% |
EMPLOYEE BENEFIT PLANS (Fair Va
EMPLOYEE BENEFIT PLANS (Fair Value Measurements of Plan Assets By Level) (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Level 3 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | $ 27,000,000 | $ 26,000,000 | $ 25,000,000 |
Level 3 | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 21,000,000 | 19,000,000 | 18,000,000 |
Level 3 | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 6,000,000 | 7,000,000 | 7,000,000 |
Pension Benefits | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 403,000,000 | 354,000,000 | 336,000,000 |
Pension Benefits | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 1,000,000 | 1,000,000 | |
Pension Benefits | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 66,000,000 | 61,000,000 | |
Pension Benefits | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 19,000,000 | 18,000,000 | |
Pension Benefits | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 72,000,000 | 67,000,000 | |
Pension Benefits | Global | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 30,000,000 | 28,000,000 | |
Pension Benefits | Fixed Income Securities | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 179,000,000 | 144,000,000 | |
Pension Benefits | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 30,000,000 | 28,000,000 | |
Pension Benefits | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 6,000,000 | 7,000,000 | |
Pension Benefits | Level 1 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 1,000,000 | 1,000,000 | |
Pension Benefits | Level 1 | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 1,000,000 | 1,000,000 | |
Pension Benefits | Level 1 | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | Global | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | Fixed Income Securities | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 1 | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 2 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 375,000,000 | 327,000,000 | |
Pension Benefits | Level 2 | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 2 | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 66,000,000 | 61,000,000 | |
Pension Benefits | Level 2 | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 19,000,000 | 18,000,000 | |
Pension Benefits | Level 2 | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 72,000,000 | 67,000,000 | |
Pension Benefits | Level 2 | Global | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 30,000,000 | 28,000,000 | |
Pension Benefits | Level 2 | Fixed Income Securities | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 179,000,000 | 144,000,000 | |
Pension Benefits | Level 2 | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 9,000,000 | 9,000,000 | |
Pension Benefits | Level 2 | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 27,000,000 | 26,000,000 | |
Pension Benefits | Level 3 | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | Global | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | Fixed Income Securities | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Benefits | Level 3 | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 21,000,000 | 19,000,000 | |
Pension Benefits | Level 3 | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 6,000,000 | 7,000,000 | |
Other Postretirement Benefits | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 17,000,000 | 14,000,000 | $ 13,000,000 |
Other Postretirement Benefits | Level 3 | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | $ 0 | $ 0 |
EMPLOYEE BENEFIT PLANS (Reconci
EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Fair Value of Level III Assets) (Details) - Level 3 - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items] | ||
Beginning of Period | $ 26 | $ 25 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 3 | 2 |
Purchases, Sales, and Settlements | (2) | (1) |
End of Period | 27 | 26 |
Private Equity | ||
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items] | ||
Beginning of Period | 7 | 7 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 1 | 1 |
Purchases, Sales, and Settlements | (2) | (1) |
End of Period | 6 | 7 |
Real Estate | ||
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items] | ||
Beginning of Period | 19 | 18 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 2 | 1 |
Purchases, Sales, and Settlements | 0 | 0 |
End of Period | $ 21 | $ 19 |
EMPLOYEE BENEFIT PLANS (Target
EMPLOYEE BENEFIT PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Details) | Dec. 31, 2017 |
Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 100.00% |
Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 100.00% |
Cash/Treasury Bills | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
Cash/Treasury Bills | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 2.00% |
United States Large Cap | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 16.00% |
United States Large Cap | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 39.00% |
United States Small Cap | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 5.00% |
United States Small Cap | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 5.00% |
Non-United States Developed | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 14.00% |
Non-United States Developed | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 7.00% |
Non-United States Emerging | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 4.00% |
Non-United States Emerging | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 9.00% |
Global Equity | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 4.00% |
Global Equity | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
Global Infrastructure | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 3.00% |
Global Infrastructure | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
Fixed Income Securities | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 45.00% |
Fixed Income Securities | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 38.00% |
Real Estate | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 8.00% |
Real Estate | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
Private Equity | Pension Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 1.00% |
Private Equity | Other Postretirement Benefits | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets (in percentage) | 0.00% |
EMPLOYEE BENEFIT PLANS (Futur81
EMPLOYEE BENEFIT PLANS (Future Benefit Payments) (Details) $ in Millions | Dec. 31, 2017USD ($) |
Pension Benefits | |
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |
2,018 | $ 21 |
2,019 | 22 |
2,020 | 23 |
2,021 | 24 |
2,022 | 25 |
Years 2023-2027 | 137 |
Other Postretirement Benefits | |
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |
2,018 | 5 |
2,019 | 5 |
2,020 | 5 |
2,021 | 6 |
2,022 | 6 |
Years 2023-2027 | $ 30 |
EMPLOYEE BENEFIT PLANS (Additio
EMPLOYEE BENEFIT PLANS (Additional Information) (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($)plan | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Number of defined benefit pension plans | plan | 3 | ||
Number of qualified defined benefit pension plans | plan | 2 | ||
Approximate percentage of net periodic benefit cost that was capitalized | 18.00% | 18.00% | 18.00% |
Investment Return Model Best-Estimate Range | 20 years | ||
Matching 401(k) contributions made | $ 6,000,000 | $ 5,000,000 | $ 5,000,000 |
Level 3 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 27,000,000 | 26,000,000 | 25,000,000 |
Pension Benefits | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Accumulated benefit obligation | 428,000,000 | 384,000,000 | |
Fair value measurements of plan assets | 403,000,000 | 354,000,000 | 336,000,000 |
Pension Benefits | Level 3 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 27,000,000 | 26,000,000 | |
Transfers between levels | 0 | 0 | |
Other Postretirement Benefits | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Employer Contribution to VEBA Trust | 3,000,000 | 2,000,000 | 4,000,000 |
Fair value measurements of plan assets | 17,000,000 | 14,000,000 | $ 13,000,000 |
Other Postretirement Benefits | FairValueInputsLevel1AndLevel2 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 17,000,000 | 14,000,000 | |
Other Postretirement Benefits | Level 3 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | $ 0 | 0 | |
Minimum | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Percentile of investment return model range used | 25.00% | ||
Maximum | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Percentile of investment return model range used | 75.00% | ||
Fixed Income Securities | Pension Benefits | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | $ 179,000,000 | 144,000,000 | |
Fixed Income Securities | Pension Benefits | Level 3 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Fixed Income Securities | Other Postretirement Benefits | FairValueInputsLevel1AndLevel2 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | 6,000,000 | 5,000,000 | |
Equities | Other Postretirement Benefits | FairValueInputsLevel1AndLevel2 | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Fair value measurements of plan assets | $ 11,000,000 | $ 9,000,000 |
SHARE-BASED COMPENSATION (Detai
SHARE-BASED COMPENSATION (Details) - 2015 Share Unit Plan - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation, valuation, share equivalent, number (in shares) | 1 | ||
Allocated share of probable payout | $ 9 | $ 4 | |
Allocated share-based compensation expense | $ 4 | $ 2 | $ 1 |
PSUs | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options awarded during the period (in shares) | 68,126 | 66,974 | 47,776 |
RSUs | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options awarded during the period (in shares) | 34,063 | 33,488 | 23,888 |
SUPPLEMENTAL CASH FLOW (Cash Tr
SUPPLEMENTAL CASH FLOW (Cash Transactions) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |||
Interest, Net of Amounts Capitalized | $ 61 | $ 61 | $ 65 |
Income Taxes (1) | $ 0 | $ 0 | $ 0 |
SUPPLEMENTAL CASH FLOW (Non-Cas
SUPPLEMENTAL CASH FLOW (Non-Cash Transactions) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |||
Net Cost of Removal Increase (Decrease) | $ (88) | $ 8 | $ 1 |
Accrued Capital Expenditures | 24 | 29 | 28 |
Commitment to Purchase Capital Lease Interests | 0 | 36 | 0 |
Asset Retirement Obligations Increase (Decrease) | $ 10 | $ (1) | $ 3 |
FAIR VALUE MEASUREMENTS AND D86
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Assets | ||
Cash Equivalents | $ 30 | $ 23 |
Restricted Cash | 12 | 7 |
Energy Derivative Contract Assets - Regulatory Recovery | 9 | 3 |
Energy Derivative Contract Assets - No Regulatory Recovery | 3 | 2 |
Total Assets | 54 | 35 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | (26) | (3) |
Derivative Liabilities - No Regulatory Recovery | (1) | |
Interest Rate Swap | (1) | (2) |
Total Liabilities | (28) | (5) |
Net Total Assets (Liabilities) | 26 | 30 |
Level 1 | ||
Assets | ||
Cash Equivalents | 30 | 23 |
Restricted Cash | 12 | 7 |
Energy Derivative Contract Assets - Regulatory Recovery | 0 | 0 |
Energy Derivative Contract Assets - No Regulatory Recovery | 0 | 0 |
Total Assets | 42 | 30 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | 0 | 0 |
Derivative Liabilities - No Regulatory Recovery | 0 | |
Interest Rate Swap | 0 | 0 |
Total Liabilities | 0 | 0 |
Net Total Assets (Liabilities) | 42 | 30 |
Level 2 | ||
Assets | ||
Cash Equivalents | 0 | 0 |
Restricted Cash | 0 | 0 |
Energy Derivative Contract Assets - Regulatory Recovery | 9 | 3 |
Energy Derivative Contract Assets - No Regulatory Recovery | 0 | 0 |
Total Assets | 9 | 3 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | (26) | (2) |
Derivative Liabilities - No Regulatory Recovery | 0 | |
Interest Rate Swap | (1) | (2) |
Total Liabilities | (27) | (4) |
Net Total Assets (Liabilities) | (18) | (1) |
Level 3 | ||
Assets | ||
Cash Equivalents | 0 | 0 |
Restricted Cash | 0 | 0 |
Energy Derivative Contract Assets - Regulatory Recovery | 0 | 0 |
Energy Derivative Contract Assets - No Regulatory Recovery | 3 | 2 |
Total Assets | 3 | 2 |
Liabilities | ||
Energy Derivative Contract Liabilities - Regulatory Recovery | 0 | (1) |
Derivative Liabilities - No Regulatory Recovery | (1) | |
Interest Rate Swap | 0 | 0 |
Total Liabilities | (1) | (1) |
Net Total Assets (Liabilities) | $ 2 | $ 1 |
FAIR VALUE MEASUREMENTS AND D87
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Energy Derivative | ||
Gross, Net, and Offsetting Amounts [Line Items] | ||
Derivative Asset, Gross Amount Recognized in the Balance Sheets | $ 12 | $ 5 |
Derivative Asset, Counterparty Netting | 10 | 2 |
Collateral Received | 0 | 0 |
Derivative Asset, Net Amount | 2 | 3 |
Derivative Liability, Fair Value, Gross Amount Recognized in the Balance Sheets | (27) | (3) |
Derivative Liability, Counterparty Netting | (10) | (2) |
Collateral Posted | 0 | 0 |
Derivative Liability, Net Amount | (17) | (1) |
Interest Rate Swap | ||
Gross, Net, and Offsetting Amounts [Line Items] | ||
Derivative Liability, Fair Value, Gross Amount Recognized in the Balance Sheets | (1) | (2) |
Derivative Liability, Counterparty Netting | 0 | 0 |
Collateral Posted | 0 | 0 |
Derivative Liability, Net Amount | $ (1) | $ (2) |
FAIR VALUE MEASUREMENTS AND D88
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Derivative [Line Items] | |
Cash Flow Hedge Loss to be Reclassified to Earnings within the next Twelve Months | $ 1 |
FAIR VALUE MEASUREMENTS AND D89
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedge - Realized Losses) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Purchased Power | $ 136,425 | $ 85,354 | $ 124,764 |
Reclassification out of Accumulated Other Comprehensive Income | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | |||
Capital Lease Interest Expense | 1,000 | 1,000 | 2,000 |
Purchased Power | $ 0 | $ 0 | $ 1,000 |
FAIR VALUE MEASUREMENTS AND D90
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Percent of gains shared with ratepayers | 10.00% | ||
Energy Derivative | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities | $ (18) | $ 12 | $ 6 |
FAIR VALUE MEASUREMENTS AND D91
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) $ in Millions, BTU in Billions | 12 Months Ended | |
Dec. 31, 2017USD ($)GWhBTU | Dec. 31, 2016GWhBTU | |
Power Contracts GWh | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | GWh | 2,589 | 2,610 |
Gas Contracts BBtu (1) | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative, Nonmonetary Notional Amount, Energy Measure | BTU | 137,952 | 12,355 |
Interest Rate Swap | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative Liability, Notional Amount | $ | $ 18 |
FAIR VALUE MEASUREMENTS AND D92
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Details) - Level 3 - Market approach - Forward Power Contracts $ in Millions | Dec. 31, 2017USD ($)$ / megawatt_hour | Dec. 31, 2016USD ($)$ / megawatt_hour |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Derivative Assets | $ | $ 3 | $ 2 |
Derivative Liabilities | $ | $ (1) | $ (1) |
Minimum | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Market Price | $ / megawatt_hour | 17.65 | 20.90 |
Maximum | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Market Price | $ / megawatt_hour | 34.60 | 40 |
FAIR VALUE MEASUREMENTS AND D93
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract] | ||
Beginning of Period | $ 1,000,000 | $ (2,000,000) |
Gains (Losses) Recorded to: | ||
Regulatory Assets or Liabilities, Derivative Instruments | 1,000,000 | 2,000,000 |
Wholesale Revenues | 4,000,000 | 4,000,000 |
Settlements | (4,000,000) | (3,000,000) |
End of Period | 2,000,000 | 1,000,000 |
Gains (Losses), Assets (Liabilities) still held | 2,000,000 | 1,000,000 |
Transfers out of Level 3 | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS AND D94
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative [Line Items] | ||
Value of derivative instruments in net liability positions with credit risk related features | $ 27,000,000 | $ 8,000,000 |
Additional collateral to post if credit-risk contingent features are triggered | 27,000,000 | |
Line of Credit Collateral | ||
Derivative [Line Items] | ||
Collateral Posted | 0 | |
Outstanding Net Payable Balances for Settled Positions | ||
Derivative [Line Items] | ||
Additional collateral to post if credit-risk contingent features are triggered | $ 12,000,000 |
FAIR VALUE MEASUREMENTS AND D95
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Face Value Long-term Debt, including Current Maturities | $ 1,466 | $ 1,466 |
Level 2 | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ||
Fair Value, Long-term Debt, including Current Maturities | $ 1,547 | $ 1,472 |
INCOME TAXES (Reconciliation of
INCOME TAXES (Reconciliation of Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | |||
Statutory tax rate | 35.00% | ||
Federal Income Tax Expense at Statutory Rate | $ 97,000 | $ 64,000 | $ 70,000 |
State Income Tax Expense, Net of Federal Deduction | 9,000 | 6,000 | 8,000 |
Federal/State Tax Credits | (9,000) | (8,000) | (8,000) |
Allowance for Equity Funds Used During Construction | (2,000) | (1,000) | (1,000) |
Deferred Tax Asset Valuation Allowance | 0 | (2,000) | 1,000 |
Impact of Enactment, TCJA | 7,000 | 0 | 0 |
Other | (1,000) | 0 | 2,000 |
Total Federal and State Income Tax Expense | $ 100,763 | $ 59,376 | $ 71,719 |
INCOME TAXES (Income Tax Expens
INCOME TAXES (Income Tax Expense Included in Income Statements) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Current Tax Expense (Benefit) | |||
Federal | $ 0 | $ 0 | $ 0 |
State | 0 | 0 | 0 |
Total Current Income Tax Expense | 0 | 0 | 0 |
Deferred Income Tax Expense | |||
Federal | 98,000 | 60,000 | 66,000 |
Federal Investment Tax Credits | (6,000) | (6,000) | (6,000) |
State | 9,000 | 5,000 | 12,000 |
Total Deferred Income Tax Expense | 101,000 | 59,000 | 72,000 |
Total Federal and State Income Tax Expense | $ 100,763 | $ 59,376 | $ 71,719 |
INCOME TAXES (The Significant C
INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Gross Deferred Income Tax Assets | ||
Capital Lease Obligations | $ 10,000 | $ 35,000 |
Operating Loss Carryforwards, Net | 56,000 | 129,000 |
Customer Advances and Contributions in Aid of Construction | 14,000 | 20,000 |
Alternative Minimum Tax Credit | 26,000 | 25,000 |
Other Postretirement Benefits | 15,000 | 23,000 |
Emission Allowance Inventory | 3,000 | 9,000 |
Investment Tax Credit Carryforward | 34,000 | 32,000 |
Income Taxes Recoverable Through Future Rates | 88,000 | 0 |
Other | 47,000 | 60,000 |
Total Gross Deferred Income Tax Assets | 293,000 | 333,000 |
Deferred Tax Assets Valuation Allowance | 0 | 0 |
Gross Deferred Income Tax Liabilities | ||
Plant, Net | (518,000) | (774,000) |
Plant Abandonments | (21,000) | 0 |
Capital Lease Assets, Net | (5,000) | (24,000) |
Pensions | (16,000) | (26,000) |
Income Taxes Payable Through Future Rates | (10,000) | 0 |
Other | (23,000) | (38,000) |
Total Gross Deferred Income Tax Liabilities | (593,000) | (862,000) |
Deferred Tax Liabilities, Net, Noncurrent | $ (300,258) | $ (529,148) |
INCOME TAXES (Summary of Tax Ca
INCOME TAXES (Summary of Tax Carryforwards) (Details) $ in Millions | Dec. 31, 2017USD ($) |
Internal Revenue Service (IRS) | |
Income Tax Contingency [Line Items] | |
Federal Net Operating Loss | $ 263 |
Tax Credits | 26 |
Investment Tax Credits | 34 |
State Tax Jurisdiction | |
Income Tax Contingency [Line Items] | |
Tax Credits | $ 8 |
INCOME TAXES (Loss and Tax Cred
INCOME TAXES (Loss and Tax Credit Carryforwards, Expiration Year) (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Minimum | Internal Revenue Service (IRS) | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2031 |
Tax Credit Carryforwards, Expiration Date | Dec. 31, 2032 |
Alternative Minimum Tax Credit Carryforwards, Expiration Date | None |
Minimum | State Tax Jurisdiction | |
Operating Loss Carryforwards [Line Items] | |
Tax Credit Carryforwards, Expiration Date | Dec. 31, 2017 |
Maximum | Internal Revenue Service (IRS) | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2034 |
Tax Credit Carryforwards, Expiration Date | Dec. 31, 2036 |
Alternative Minimum Tax Credit Carryforwards, Expiration Date | None |
Maximum | State Tax Jurisdiction | |
Operating Loss Carryforwards [Line Items] | |
Tax Credit Carryforwards, Expiration Date | Dec. 31, 2029 |
INCOME TAXES (Uncertain Tax Pos
INCOME TAXES (Uncertain Tax Positions) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Beginning of Period | $ 12 | $ 5 |
Additions Based on Tax Positions Taken in the Current Year | 7 | 7 |
Reduction to Positions, TCJA | (6) | 0 |
End of Period | $ 13 | $ 12 |
INCOME TAXES (Additional Inform
INCOME TAXES (Additional Information) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
Increase in income tax expense due to change in tax rate | $ 7,000,000 | ||
Increase in regulated liabilities due to change in tax rate | 343,000,000 | ||
Decrease deferred tax liabilities due to change in tax rate | (336,000,000) | ||
Unrecognized tax benefits, if recognized, decrease in income tax expense (benefit) | 1,000,000 | $ 1,000,000 | |
Interest expense related to uncertain tax position | 0 | 0 | $ 0 |
Interest payable | 0 | 0 | |
Penalties accrued | $ 0 | $ 0 |
QUARTERLY FINANCIAL DATA (UN103
QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating Revenue | $ 304,000 | $ 417,000 | $ 352,000 | $ 268,000 | $ 281,000 | $ 394,000 | $ 317,000 | $ 243,000 | $ 1,340,935 | $ 1,234,995 | $ 1,306,544 |
Operating Income | 44,000 | 138,000 | 107,000 | 37,000 | 37,000 | 122,000 | 72,000 | 12,000 | 326,326 | 243,131 | 259,303 |
Net Income (Loss) | $ 13,000 | $ 82,000 | $ 61,000 | $ 21,000 | $ 12,000 | $ 72,000 | $ 41,000 | $ (1,000) | $ 176,668 | $ 124,438 | $ 127,794 |