Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended | |
Sep. 30, 2014 | Oct. 20, 2014 | |
Document Documentand Entity Information [Abstract] | ' | ' |
Document Type | '10-Q | ' |
Amendment Flag | 'false | ' |
Document Period End Date | 30-Sep-14 | ' |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q3 | ' |
Entity Registrant Name | 'TUCSON ELECTRIC POWER COMPANY | ' |
Entity Central Index Key | '0000100122 | ' |
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 |
CONDENCED_CONSOLIDATED_BALANCE
CONDENCED CONSOLIDATED BALANCE SHEETS (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Utility Plant | ' | ' |
Plant in Service | $4,675,441 | $4,467,667 |
Utility Plant Under Capital Leases | 747,158 | 637,957 |
Construction Work in Progress | 173,022 | 180,485 |
Total Utility Plant | 5,595,621 | 5,286,109 |
Less Accumulated Depreciation and Amortization | -1,909,448 | -1,826,977 |
Less Accumulated Amortization of Capital Lease Assets | -531,159 | -514,677 |
Total Utility Plant—Net | 3,155,014 | 2,944,455 |
Investments and Other Property | ' | ' |
Investments in Lease Equity | 36,086 | 36,194 |
Other | 36,201 | 33,488 |
Total Investments and Other Property | 72,287 | 69,682 |
Current Assets | ' | ' |
Cash and Cash Equivalents | 28,208 | 25,335 |
Accounts Receivable—Customer | 110,906 | 80,211 |
Unbilled Accounts Receivable | 49,743 | 34,369 |
Allowance for Doubtful Accounts | -5,136 | -4,825 |
Accounts Receivable—Due from Affiliates | 3,281 | 6,064 |
Materials and Supplies | 80,475 | 75,200 |
Deferred Income Taxes—Current | 111,593 | 70,722 |
Fuel Inventory | 39,027 | 44,027 |
Regulatory Assets—Current | 66,877 | 42,555 |
Derivative Instruments | 699 | 2,137 |
Other | 13,923 | 12,923 |
Total Current Assets | 499,596 | 388,718 |
Regulatory and Other Assets | ' | ' |
Regulatory Assets—Noncurrent | 162,872 | 141,030 |
Derivative Instruments | 212 | 167 |
Other Assets | 20,587 | 19,233 |
Total Regulatory and Other Assets | 183,671 | 160,430 |
Total Assets | 3,910,568 | 3,563,285 |
Capitalization | ' | ' |
Common Stock Equity | 1,017,778 | 925,923 |
Capital Lease Obligations | 68,424 | 131,370 |
Long-Term Debt | 1,372,369 | 1,223,070 |
Total Capitalization | 2,458,571 | 2,280,363 |
Current Liabilities | ' | ' |
Current Obligations Under Capital Leases | 191,951 | 186,056 |
Borrowings Under Revolving Credit Facility | 35,000 | 0 |
Accounts Payable—Trade | 83,571 | 88,556 |
Accounts Payable—Due to Affiliates | 4,099 | 9,153 |
Accrued Taxes Other than Income Taxes | 53,230 | 34,485 |
Accrued Employee Expenses | 18,134 | 24,454 |
Regulatory Liabilities—Current | 37,125 | 23,701 |
Accrued Interest | 20,043 | 22,785 |
Customer Deposits | 20,370 | 21,354 |
Derivative Instruments | 6,664 | 5,531 |
Other | 8,420 | 9,244 |
Total Current Liabilities | 478,607 | 425,319 |
Deferred Credits and Other Liabilities | ' | ' |
Deferred Income Taxes—Noncurrent | 509,062 | 428,103 |
Regulatory Liabilities—Noncurrent | 302,912 | 263,270 |
Pension and Other Postretirement Benefits | 79,911 | 84,936 |
Derivative Instruments | 3,393 | 5,161 |
Other | 78,112 | 76,133 |
Total Deferred Credits and Other Liabilities | 973,390 | 857,603 |
Commitments, Contingencies & Environmental Matters (Note 5) | ' | ' |
Total Capitalization and Other Liabilities | $3,910,568 | $3,563,285 |
CONSOLIDATED_STATEMENTS_OF_INC
CONSOLIDATED STATEMENTS OF INCOME (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Operating Revenues | ' | ' | ' | ' |
Electric Retail Sales | $316,387 | $310,632 | $760,192 | $739,147 |
Electric Wholesale Sales | 37,053 | 26,563 | 111,692 | 90,503 |
Other Revenues | 33,971 | 34,044 | 92,658 | 93,603 |
Total Operating Revenues | 387,411 | 371,239 | 964,542 | 923,253 |
Operating Expenses | ' | ' | ' | ' |
Fuel | 89,199 | 82,065 | 225,163 | 247,417 |
Purchased Energy | 49,902 | 42,477 | 125,423 | 89,815 |
Transmission and Other PPFAC Recoverable Costs | 5,222 | 4,940 | 12,683 | 7,535 |
Increase (Decrease) to Reflect PPFAC Recovery Treatment | -5,376 | -7,992 | -20,167 | -5,079 |
Total Fuel and Purchased Energy | 138,947 | 121,490 | 343,102 | 339,688 |
Operations and Maintenance | 112,667 | 79,335 | 273,784 | 239,170 |
Depreciation | 31,966 | 30,311 | 93,857 | 87,729 |
Amortization | 6,973 | 6,118 | 21,449 | 24,393 |
Taxes Other Than Income Taxes | 11,960 | 10,808 | 35,800 | 32,916 |
Total Operating Expenses | 302,513 | 248,062 | 767,992 | 723,896 |
Operating Income | 84,898 | 123,177 | 196,550 | 199,357 |
Other Income (Deductions) | ' | ' | ' | ' |
Interest Income | 7 | 6 | 181 | 14 |
Other Income | 2,024 | 1,466 | 6,123 | 3,904 |
Other Expense | -7,170 | -2,776 | -11,979 | -7,493 |
Appreciation (Depreciation) in Fair Value of Investments | -504 | 731 | 375 | 1,864 |
Total Other Income (Deductions) | -5,643 | -573 | -5,300 | -1,711 |
Interest Expense | ' | ' | ' | ' |
Long-Term Debt | 15,579 | 13,848 | 45,326 | 42,412 |
Capital Leases | 1,202 | 6,323 | 9,048 | 18,821 |
Other Interest Expense | 104 | 82 | 557 | -86 |
Interest Capitalized | -850 | -644 | -2,878 | -1,671 |
Total Interest Expense | 16,035 | 19,609 | 52,053 | 59,476 |
Income Before Income Taxes | 63,220 | 102,995 | 139,197 | 138,170 |
Income Tax Expense | 23,576 | 38,828 | 51,656 | 41,737 |
Net Income | $39,644 | $64,167 | $87,541 | $96,433 |
CONDENSED_CONSOLIDATED_STATEME
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Statement of Comprehensive Income [Abstract] | ' | ' | ' | ' |
Net Income | $39,644 | $64,167 | $87,541 | $96,433 |
Other Comprehensive Income | ' | ' | ' | ' |
Net Changes in Fair Value of Cash Flow Hedges: | 697 | 700 | 1,672 | 2,156 |
Supplemental Executive Retirement Plan (SERP) Benefit Amortization: | 25 | 68 | 74 | 205 |
Total Other Comprehensive Income, Net of Taxes | 722 | 768 | 1,746 | 2,361 |
Total Comprehensive Income | $40,366 | $64,935 | $89,287 | $98,794 |
CONSOLIDATED_STATEMENTS_OF_COM
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Statement of Comprehensive Income [Abstract] | ' | ' | ' | ' |
Income Tax Expense in Fair Value of Cash Flow Hedges | $450 | $458 | $1,117 | $1,412 |
Income Tax on Supplemental Executive Retirement Plan (SERP) Benefit Adjustments to Net Income | ' | $42 | ' | $127 |
CONSOLIDATED_STATEMENTS_OF_CAS
CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 9 Months Ended | |
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 |
Cash Flows from Operating Activities | ' | ' |
Net Income | $87,541 | $96,433 |
Depreciation | 93,857 | 87,729 |
Amortization Expense | 21,449 | 24,393 |
Amortization of Deferred Debt-Related Costs included in Interest Expense | 1,959 | 1,831 |
Use of Renewable Energy Credits for Compliance | 15,129 | 11,766 |
Deferred Income Taxes | 53,991 | 53,381 |
Pension and Retiree Expense | 10,236 | 14,909 |
Pension and Retiree Funding | -12,989 | -26,118 |
Share-Based Compensation Expense | 5,010 | 2,239 |
Allowance for Equity Funds Used During Construction | -4,983 | -2,923 |
LFCR Revenue | -8,350 | 0 |
Increase (Decrease) to Reflect PPFAC Recovery Treatment | -20,167 | -5,079 |
Fortis Acquisition Direct Customer Benefit | 18,870 | 0 |
PPFAC Reduction - 2013 TEP Rate Order | 0 | 3,000 |
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately[Abstract] | ' | ' |
Accounts Receivable | -45,758 | -41,227 |
Materials and Fuel Inventory | -274 | 14,955 |
Accounts Payable | -472 | -8,678 |
Income Taxes | -25 | -10,681 |
Interest Accrued | -3,849 | 1,008 |
Taxes Other Than Income Taxes | 18,745 | 17,405 |
Other | -8,652 | 19,836 |
Net Cash Flows – Operating Activities | 221,268 | 254,179 |
Cash Flows from Investing Activities | ' | ' |
Capital Expenditures | -227,153 | -180,451 |
Purchase of Intangibles—Renewable Energy Credits | -22,047 | -17,552 |
Return of Investments in Springerville Lease Debt | 0 | 9,104 |
Restricted Cash Released | 0 | 4,500 |
Other, net | 12,883 | 4,656 |
Net Cash Flows—Investing Activities | -236,317 | -179,743 |
Cash Flows from Financing Activities | ' | ' |
Proceeds from Borrowings Under Revolving Credit Facility | 190,000 | 78,000 |
Repayments of Borrowings Under Revolving Credit Facility | -155,000 | -78,000 |
Proceeds from Issuance of Long-Term Debt | 149,168 | 0 |
Payments of Capital Lease Obligations | -165,145 | -99,621 |
Dividends Paid to UNS Energy | 0 | -20,000 |
Payment of Debt Issue/Retirement Costs | -1,652 | -1,022 |
Other, net | 551 | 1,250 |
Net Cash Flows—Financing Activities | 17,922 | -119,393 |
Net Increase (Decrease) in Cash and Cash Equivalents | 2,873 | -44,957 |
Cash and Cash Equivalents, Beginning of Year | 25,335 | 79,743 |
Cash and Cash Equivalents, End of Period | $28,208 | $34,786 |
CONSOLIDATED_STATEMENT_OF_CHAN
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (USD $) | Total | Common Stock [Member] | Capital Stock Expense [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Loss [Member] |
In Thousands, unless otherwise specified | |||||
Balances at December 31, 2013 at Dec. 31, 2013 | $925,923 | $888,971 | ($6,357) | $49,185 | ($5,876) |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ' | ' | ' | ' | ' |
Net Income | 87,541 | ' | ' | ' | ' |
Other Comprehensive Loss, net of tax | 1,746 | ' | ' | ' | ' |
Other | 2,568 | 2,568 | ' | ' | ' |
Balances at September 30, 2014 at Sep. 30, 2014 | $1,017,778 | $891,539 | ($6,357) | $136,726 | ($4,130) |
NATURE_OF_OPERATIONS_AND_FINAN
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION | 9 Months Ended | |
Sep. 30, 2014 | ||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' | |
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION | ' | |
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION | ||
Tucson Electric Power Company (TEP) is a regulated utility that generates, transmits and distributes electricity to approximately 415,000 retail electric 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. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State Generation and Transmission Association, Inc. (Tri-State) and Springerville Unit 4 on behalf of Salt River Project Agricultural Improvement and Power District (SRP). TEP is a wholly owned subsidiary of UNS Energy Corporation (UNS Energy), a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis Inc. (Fortis), which is a leader in the North American electric and gas utility business. | ||
FORTIS ACQUISITION OF UNS ENERGY | ||
On December 11, 2013, UNS Energy, the parent of TEP, announced that it had entered into an Agreement and Plan of Merger (Merger) to be acquired by Fortis for $60.25 per share of UNS Energy common stock in cash. The acquisition contemplated by this agreement was completed effective August 15, 2014. | ||
Prior to completion of the Merger, UNS Energy obtained the approval of its shareholders, the Federal Energy Regulatory Commission (FERC), and the Arizona Corporation Commission (ACC). The ACC's approval was subject to certain stipulations, including, but not limited to, the following: | ||
• | TEP will provide credits on retail customers' bills totaling $19 million over five years: approximately $6 million in year one and $3 million annually in years two through five. The monthly bill credits will be applied each year from October through March effective October 1, 2014; | |
• | TEP, along with UNS Energy and its other affiliated subsidiaries, will adopt certain ring-fencing and corporate governance provisions; | |
• | Dividends paid from TEP to UNS Energy cannot exceed 60 percent of TEP's annual net income for a period of five years or until such time that TEP's equity capitalization reaches 50 percent of total capital. The ratios used to determine the dividend restrictions will be calculated each calendar year and reported to the ACC annually beginning on April 1, 2016; and | |
• | Fortis making an equity investment totaling $220 million to UNS Energy and its regulated subsidiaries, including TEP. Following the close of the Merger, Fortis exceeded the investment requirement by contributing $37 million to UNS Energy on August 15, 2014 and $200 million to UNS Energy on October 10, 2014. On October 10, 2014, UNS Energy contributed $175 million of the investment to TEP. | |
As a result of the Merger being completed, TEP recorded approximately $15 million through August 2014 as its allocated share of merger-related expenses, in addition to the customer bill credits discussed above. Merger-related expenses include investment banker fees, legal expenses, and accelerated expenses for certain share-based compensation awards. | ||
SHARE-BASED COMPENSATION EXPENSE | ||
Completion of the Merger resulted in accelerated vesting and expense recognition of all outstanding non-vested UNS Energy share-based awards that would otherwise have been recognized over remaining vesting periods through February 2017. TEP recognized approximately $2 million of expense in the third quarter of 2014 due to the accelerated vesting of the awards. TEP recorded total share-based compensation expense of $4 million for the three months ended September 30, 2014 and $1 million for the three months ended September 30, 2013. For the nine months ended September 30, 2014 and 2013, TEP recorded $5 million and $3 million of share-based compensation expense, respectively. In August 2014, UNS Energy settled all outstanding share-based compensation awards in cash. | ||
BASIS OF PRESENTATION | ||
We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2013 Annual Report on Form 10-K. | ||
The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, our quarterly results are not indicative of annual operating results. | ||
TEP did not reflect the impacts of acquisition accounting in its financial statements. All adjustments of assets and liabilities to fair value and the resultant goodwill associated with the Merger were recorded by FortisUS Inc., a wholly owned subsidiary of Fortis. | ||
As a result of the Fortis Merger, TEP has elected to change its method of reporting cash flows from the direct to the indirect method to conform to the presentation method elected by Fortis. Certain amounts from prior periods have been reclassified to conform to the current period presentation. | ||
REVISION OF PRIOR PERIOD BALANCE SHEETS | ||
TEP revised its December 31, 2013 balance sheet to correct an error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. We do not believe the misclassification was material to the previously issued financial statements. | ||
RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS | ||
In 2014, we adopted accounting guidance that: | ||
• | requires an entity to recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay and any additional amount the entity expects to pay on behalf of its co-obligors. The adoption of this guidance did not have a material impact on our disclosures, financial condition, results of operations, or cash flows. | |
• | impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows. |
REGULATORY_MATTERS
REGULATORY MATTERS | 9 Months Ended |
Sep. 30, 2014 | |
Regulated Operations [Abstract] | ' |
REGULATORY MATTERS | ' |
REGULATORY MATTERS | |
The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. | |
The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales. | |
COST RECOVERY MECHANISMS | |
Purchased Power and Fuel Adjustment Clause | |
In April 2014, the ACC approved a Purchased Power and Fuel Adjustment Clause (PPFAC) rate for TEP of 0.10 cents per kWh for the period May through September 2014 and 0.50 cents per kWh for the period October 2014 through March 2015. TEP's PPFAC rate was a credit of approximately 0.14 cents per kWh for the period July 2013 through April 2014. | |
San Juan Mine Fire Insurance Proceeds | |
In September 2011, a fire at the underground mine providing coal to San Juan Generating Station (San Juan) caused interruptions to mining operations and resulted in increased fuel costs. The 2013 TEP Rate Order required TEP to defer incremental fuel costs of $10 million from recovery under the PPFAC pending final resolution of an insurance claim by the San Juan Coal Company and distribution of insurance proceeds to San Juan participants. As of September 30, 2014, TEP has received insurance settlement proceeds of $8 million and expects to receive substantially all of the outstanding balance in the fourth quarter. The proceeds offset the deferred costs and are reflected in our cash flow statements as an other operating cash receipt. TEP expects to recover any remaining fuel costs, not reimbursed by insurance, through its PPFAC. | |
Environmental Compliance Adjustor | |
The 2013 TEP Rate Order provided an Environmental Compliance Adjustor (ECA) to recover the return on and of qualified investments to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP expects to recognize ECA revenues of less than $1 million in 2014. | |
Energy Efficiency Standards | |
TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs as well as a performance incentive. In the first nine months of 2014, TEP recorded a DSM performance incentive of $2 million that is included in Electric Retail Sales in the TEP Income Statement. | |
Lost Fixed Cost Recovery Mechanism | |
The Lost Fixed Cost Recovery (LFCR) mechanism provides recovery of certain non-fuel costs that would go unrecovered due to lost retail kWh sales as a result of implementing ACC approved EE programs and distributed generation (DG) targets. For recovery of lost fixed costs, TEP is required to file an annual LFCR adjustment request with the ACC for costs related to the prior year, and recovery is subject to a year-over-year cap of 1% of the company's total retail revenues. | |
TEP recorded, in Electric Retail Sales, LFCR revenues of $8 million in the first nine months of 2014 related to reductions in retail kWh sales for 2013 and 2014. We recognize LFCR revenue when verifiable regardless of when the lost retail kWh sales occur. | |
The ACC approved TEP's annual LFCR recovery request for lost fixed costs incurred in 2013 of approximately $5 million. The approved rates, of approximately 0.41% of retail revenue for EE and approximately 0.31% of retail revenue for DG, became effective August 2014. |
RELATED_PARTY_TRANSACTIONS_REL
RELATED PARTY TRANSACTIONS RELATED PARTY TRANSACTIONS | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Related Party Transactions [Abstract] | ' | |||||||||||||||
RELATED PARTY TRANSACTIONS | ' | |||||||||||||||
RELATED PARTY TRANSACTIONS | ||||||||||||||||
TEP engages in various transactions with affiliated subsidiaries of UNS Energy including UNS Electric, Inc., (UNS Electric), UNS Gas, Inc. (UNS Gas) and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy affiliates). These transactions include sales and purchases of power, common cost allocations, and the provision of corporate and other labor related services. Additionally, TEP and UNS Electric are planning the joint purchase of a generating station unit. See Note 6. | ||||||||||||||||
The following table summarizes related party transactions: | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Millions of Dollars | ||||||||||||||||
Wholesale Sales - TEP to UNS Electric (1) | $ | 2 | $ | — | $ | 3 | $ | 1 | ||||||||
Wholesale Sales - UNS Electric to TEP (1) | 2 | — | 3 | 1 | ||||||||||||
Control Area Services - TEP to UNS Electric (2) | 1 | 1 | 2 | 3 | ||||||||||||
Common Costs - TEP to UNS Energy Affiliates (3) | 3 | 3 | 10 | 9 | ||||||||||||
Supplemental Workforce - SES to TEP (4) | 4 | 4 | 12 | 11 | ||||||||||||
Corporate Services and Other Labor Charges - TEP to UNS Energy Affiliates (5) | 3 | 4 | 7 | 10 | ||||||||||||
Corporate Services - UNS Energy Affiliates to TEP (5) | — | — | 1 | 1 | ||||||||||||
(1) | TEP and UNS Electric sell power to each other at prevailing market prices. | |||||||||||||||
(2) | TEP charges UNS Electric for control area services under a FERC-accepted Control Area Services Agreement. | |||||||||||||||
(3) | Common costs (systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable. | |||||||||||||||
(4) | SES provides supplemental workforce and meter-reading services to TEP. Amounts are based on costs of services performed, and management believes that the charges for the services are reasonable. | |||||||||||||||
(5) | All Corporate Services (finance, accounting, tax, legal and information technology) and other labor services are directly assigned to the benefiting entity at a fully burdened cost when possible; other costs are allocated using the Massachusetts' Formula, an industry accepted method of allocating common costs to affiliated entities. | |||||||||||||||
At September 30, 2014 and December 31, 2013, our Balance Sheets include the following intercompany balances: | ||||||||||||||||
Balances at | ||||||||||||||||
30-Sep-14 | 31-Dec-13 | |||||||||||||||
Millions of Dollars | ||||||||||||||||
Receivables from Related Parties | ||||||||||||||||
UNS Electric | $ | 2 | $ | 3 | ||||||||||||
UNS Gas | 1 | 2 | ||||||||||||||
UNS Energy | — | 1 | ||||||||||||||
Total Due from Related Parties | $ | 3 | $ | 6 | ||||||||||||
Payables to Related Parties | ||||||||||||||||
SES | $ | 3 | $ | 2 | ||||||||||||
UNS Electric | 1 | — | ||||||||||||||
UNS Energy | — | 7 | ||||||||||||||
Total Due to Related Parties | $ | 4 | $ | 9 | ||||||||||||
DEBT_AND_CAPITAL_LEASE_OBLIGAT
DEBT AND CAPITAL LEASE OBLIGATIONS | 9 Months Ended |
Sep. 30, 2014 | |
Debt and Capital Lease Obligations [Abstract] | ' |
DEBT AND CAPITAL LEASE OBLIGATIONS | ' |
DEBT AND CAPITAL LEASE OBLIGATIONS | |
We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2013 Annual Report on Form 10-K. | |
SPRINGERVILLE COAL HANDLING FACILITIES CAPITAL LEASE PURCHASE COMMITMENT | |
In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Due to TEP’s purchase commitment, in April of 2014, TEP recorded an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheet in the amount of $109 million, which represented the present value of the total purchase commitment. | |
TEP previously agreed with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities Leases were not renewed, TEP would exercise the purchase option under those contracts. Upon TEP's purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. No amounts have been recorded for these commitments from SRP and Tri-State at September 30, 2014. | |
2014 UNSECURED NOTES ISSUED | |
In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. TEP may redeem the notes prior to September 15, 2043, with a make-whole premium plus accrued interest. After September 15, 2043, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to repay approximately $90 million on the outstanding borrowings under the revolving credit facility with the remaining proceeds used for general corporate purposes. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding. | |
TEP CREDIT AGREEMENT | |
The TEP Credit Agreement consists of a $200 million revolving credit and LOC facility together with an $82 million LOC facility to support tax-exempt bonds. As of September 30, 2014, there is $149 million available under the revolving credit facility. The TEP Credit Agreement expires in November 2016. As of October 20, 2014, TEP had $185 million available under its revolving credit facility. | |
TEP provided, in the second quarter of 2014, a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement is reduced by $15 million until the Gila River transaction closes and the LOC is terminated. See Note 6. | |
COVENANT COMPLIANCE | |
At September 30, 2014, we were in compliance with the terms of our loan and credit agreements. |
COMMITMENTS_CONTINGENCIES_AND_
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS | 9 Months Ended | |||||||||||||||||||||||||||
Sep. 30, 2014 | ||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | |||||||||||||||||||||||||||
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS | ' | |||||||||||||||||||||||||||
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS | ||||||||||||||||||||||||||||
COMMITMENTS | ||||||||||||||||||||||||||||
In addition to those reported in our 2013 Annual Report on Form 10-K, TEP entered into the following long-term commitments through September 30, 2014: | ||||||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | ||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||
Fuel, Including Transportation | $ | — | $ | 9 | $ | 9 | $ | 10 | $ | 10 | $ | 42 | $ | 80 | ||||||||||||||
Purchased Power | — | 18 | — | — | — | — | 18 | |||||||||||||||||||||
Renewable Power Purchase Agreements (PPA)(2) | 6 | 5 | 5 | 5 | 5 | 60 | 86 | |||||||||||||||||||||
Capital Lease Obligations(1) | — | 120 | — | — | — | — | 120 | |||||||||||||||||||||
Total Purchase Commitments | $ | 6 | $ | 152 | $ | 14 | $ | 15 | $ | 15 | $ | 102 | $ | 304 | ||||||||||||||
(1) | In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 4. | |||||||||||||||||||||||||||
(2) | In July 2014, TEP entered into a 20-year PPA with a renewable energy generation facility that achieved commercial operation in July 2014. TEP is obligated to purchase 100% of the output from this facility. The amounts in the table also reflect updated estimated annual production for existing contracts which increased the minimum annual payment obligations. | |||||||||||||||||||||||||||
CONTINGENCIES | ||||||||||||||||||||||||||||
Planned Purchase of Gas-Fired Generation Facility | ||||||||||||||||||||||||||||
In 2013, TEP and UNS Electric, an affiliate of TEP, entered into an agreement to purchase a gas-fired generation facility. See Note 6. | ||||||||||||||||||||||||||||
Claims Related to San Juan Generating Station | ||||||||||||||||||||||||||||
San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan. | ||||||||||||||||||||||||||||
In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations. | ||||||||||||||||||||||||||||
Claims Related to Four Corners Generating Station | ||||||||||||||||||||||||||||
In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. In August 2014, APS submitted a counteroffer with revised settlement terms. The joint participants have agreed to have the matter stayed until November 2014 to make continued progress toward a final agreement that would resolve this matter without further litigation. | ||||||||||||||||||||||||||||
TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP's estimated share of the settlement offer submitted by APS in August 2014 is less than $1 million. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for this claim, TEP cannot determine estimates of the range of costs at this time. | ||||||||||||||||||||||||||||
In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. In December 2013, the coal supplier and Four Corners’ operating agent filed a claim contesting the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. The New Mexico Taxation and Revenue Department and APS started settlement negotiations in July 2014. TEP cannot predict the outcome or timing of resolution of this claim. | ||||||||||||||||||||||||||||
Mine Closure Reclamation at Generating Stations Not Operated by TEP | ||||||||||||||||||||||||||||
TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final 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 $44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $21 million at September 30, 2014 and $18 million at December 31, 2013. | ||||||||||||||||||||||||||||
Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. 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 us to pass through most fuel costs, including final reclamation costs, to 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. | ||||||||||||||||||||||||||||
Discontinued Transmission Project | ||||||||||||||||||||||||||||
TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. At this time, TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC that recent transmission additions by TEP and UNS Electric support elimination of this project. TEP and UNS Electric plan to keep the path approved in the line siting matter in contemplation of using a greater part of the route to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from the FERC before seeking rate recovery from the ACC. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery in TEP's next FERC rate case. | ||||||||||||||||||||||||||||
Performance Guarantees | ||||||||||||||||||||||||||||
The participants in each of the remote generating stations in which TEP participates, including TEP, have guaranteed certain performance obligations of the other participants. Specifically, in the event of payment default of a participant, the non-defaulting participants have agreed to bear a 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 generating capacity of the defaulting participants. As of September 30, 2014, there have been no such payment defaults under any of the remote generating station agreements. TEP's joint participation agreements expire in 2016 through 2046. | ||||||||||||||||||||||||||||
ENVIRONMENTAL MATTERS | ||||||||||||||||||||||||||||
Environmental Regulation | ||||||||||||||||||||||||||||
The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers. | ||||||||||||||||||||||||||||
Hazardous Air Pollutant Requirements | ||||||||||||||||||||||||||||
In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics (MATS) rules, additional emission control equipment will be required by April 2015. TEP, as operator of Springerville and Sundt, and the operator of Navajo have received extensions until April 2016 to comply with the MATS rules. TEP's share of the estimated costs to comply with the MATS rules includes the following: | ||||||||||||||||||||||||||||
Estimated Mercury Emissions Control Costs: | Navajo | Springerville(1) | ||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||
Capital Expenditures | $ | 1 | $ | 5 | ||||||||||||||||||||||||
Annual O&M Expenses | 1 | 1 | ||||||||||||||||||||||||||
(1) | Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2. | |||||||||||||||||||||||||||
TEP expects Four Corners, Sundt, and San Juan's current emission controls to be adequate to comply with the EPA's MATS rules. A study determined that Four Corners' emission controls are adequate. Therefore, TEP expects no additional capital expenditures or O&M expenses will be incurred to comply. Although expected to be compliant, Sundt would be required to install additional monitoring equipment, at an estimated cost of less than $1 million, to continue to burn coal after the MATS rules become effective. | ||||||||||||||||||||||||||||
Regional Haze Rules | ||||||||||||||||||||||||||||
The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants. | ||||||||||||||||||||||||||||
In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install selective catalytic reduction (SCR). Complying with the EPA’s BART rules, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. BART provisions of Regional Haze Rules requiring emission control upgrades do not apply to Springerville because the BART rules apply to plants built prior to Springerville. TEP cannot predict the ultimate outcome of these matters. | ||||||||||||||||||||||||||||
TEP's estimated costs involved in meeting these rules are: | ||||||||||||||||||||||||||||
Estimated NOx Emissions Control Costs: | Navajo (1) | San Juan (2) | Four Corners (3) | Sundt (4) | ||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||
Capital Expenditures | $ | 42 | $ | 35 | $ | 35 | $ | 12 | ||||||||||||||||||||
Annual O&M Expenses | 1 | 1 | 2 | 6-May | ||||||||||||||||||||||||
-1 | In August 2014, the EPA published a final rule approving a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year. | |||||||||||||||||||||||||||
-2 | In October 2014, the EPA published a final rule approving a state plan covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016. Corresponding to that action, the EPA withdrew the previously applicable FIP addressing the same requirements. Prior to the shutdown of any units in San Juan, PNM must obtain New Mexico Public Regulation Commission approval. If Unit 2 is retired early, TEP expects to request ACC approval to recover all costs associated with the early closure of the unit. TEP owns 50% of San Juan Unit 2. At September 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $111 million. | |||||||||||||||||||||||||||
-3 | In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5. | |||||||||||||||||||||||||||
(4) In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At September 30, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover all the remaining costs of the coal handling facilities. |
PLANNED_PURCHASE_OF_GASFIRED_G
PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY | 9 Months Ended |
Sep. 30, 2014 | |
Other Commitments [Abstract] | ' |
PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY | ' |
PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY | |
In December 2013, TEP and UNS Electric, an affiliate of TEP, entered into a purchase agreement with a subsidiary of Entegra to purchase Gila River Unit 3 for $219 million, subject to certain closing adjustments. Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW, is located in Gila Bend, Arizona. TEP expects to purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million, and UNS Electric expects to purchase the remaining 25% undivided interest (137 MW) for approximately $55 million. In October 2014, the FERC issued an order authorizing the transaction. The closing of the transaction remains subject to certain other closing conditions and finalizing various closing documents. TEP and UNS Electric expect the transaction to close in December 2014. | |
In June 2014, TEP provided a letter of credit (LOC) for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. The seller is entitled to draw upon the LOC and apply such amount as liquidated damages if it has validly terminated the purchase agreement as a result of misrepresentations by TEP and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the LOC will be canceled. In August 2014, Entegra filed a prepackaged Chapter 11 bankruptcy in the U.S. Bankruptcy Court for the District of Delaware. In September 2014, Entegra's Chapter 11 bankruptcy plan was confirmed. TEP does not expect the bankruptcy to impact the purchase of Gila River Unit 3. |
EMPLOYEE_BENEFIT_PLANS
EMPLOYEE BENEFIT PLANS | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Text Block [Abstract] | ' | |||||||||||||||
EMPLOYEE BENEFIT PLANS | ' | |||||||||||||||
EMPLOYEE BENEFIT PLANS | ||||||||||||||||
Net periodic benefit plan cost includes the following components: | ||||||||||||||||
Pension Benefits | Other Retiree Benefits | |||||||||||||||
Three Months Ended September 30, | ||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Millions of Dollars | ||||||||||||||||
Service Cost | $ | 2 | $ | 3 | $ | 1 | $ | 1 | ||||||||
Interest Cost | 4 | 4 | — | — | ||||||||||||
Expected Return on Plan Assets | (5 | ) | (5 | ) | — | — | ||||||||||
Actuarial Loss Amortization | 1 | 2 | — | — | ||||||||||||
Net Periodic Benefit Cost | $ | 2 | $ | 4 | $ | 1 | $ | 1 | ||||||||
Pension Benefits | Other Retiree Benefits | |||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Millions of Dollars | ||||||||||||||||
Service Cost | $ | 7 | $ | 8 | $ | 3 | $ | 3 | ||||||||
Interest Cost | 12 | 11 | 2 | 2 | ||||||||||||
Expected Return on Plan Assets | (16 | ) | (14 | ) | (1 | ) | (1 | ) | ||||||||
Actuarial Loss Amortization | 3 | 6 | — | — | ||||||||||||
Net Periodic Benefit Cost | $ | 6 | $ | 11 | $ | 4 | $ | 4 | ||||||||
SUPPLEMENTAL_CASH_FLOW_INFORMA
SUPPLEMENTAL CASH FLOW INFORMATION | 9 Months Ended |
Sep. 30, 2014 | |
Text Block [Abstract] | ' |
SUPPLEMENTAL CASH FLOW INFORMATION | ' |
SUPPLEMENTAL CASH FLOW INFORMATION | |
NON-CASH TRANSACTIONS | |
In April 2014, TEP recorded an increase of $109 million to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases due to TEP's commitment to purchase leased interests in April 2015. See Note 4. | |
In August 2013, TEP recorded an increase of $39 million to both Utility Plant Under Capital Leases and Capital Lease Obligations due to TEP's commitment to purchase leased interests in Springerville Unit 1 in January 2015. | |
In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction. |
FAIR_VALUE_MEASUREMENTS_AND_DE
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | 9 Months Ended | |||||||||||||||||||||||
Sep. 30, 2014 | ||||||||||||||||||||||||
Disclosure Text Block [Abstract] | ' | |||||||||||||||||||||||
FAIR VALUE MEASUREMENTS & DERIVATIVE INSTRUMENTS | ' | |||||||||||||||||||||||
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | ||||||||||||||||||||||||
We categorize our assets and liabilities accounted for at fair value 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. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. | ||||||||||||||||||||||||
Total | Level 1 | Level 2 | Level 3 | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | Net Amount | |||||||||||||||||||
30-Sep-14 | ||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||
Cash Equivalents(1) | $ | 10 | $ | 10 | $ | — | $ | — | $ | — | $ | 10 | ||||||||||||
Restricted Cash(1) | 2 | 2 | — | — | — | 2 | ||||||||||||||||||
Rabbi Trust Investments(2) | 25 | — | 25 | — | — | 25 | ||||||||||||||||||
Energy Contracts - Regulatory Recovery(3) | 1 | — | 1 | — | (1 | ) | — | |||||||||||||||||
Total Assets | 38 | 12 | 26 | — | (1 | ) | 37 | |||||||||||||||||
Liabilities | ||||||||||||||||||||||||
Energy Contracts - Regulatory Recovery(3) | (5 | ) | — | (2 | ) | (3 | ) | 1 | (4 | ) | ||||||||||||||
Energy Contracts - Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | |||||||||||||||
Interest Rate Swaps(4) | (4 | ) | — | (4 | ) | — | — | (4 | ) | |||||||||||||||
Total Liabilities | (10 | ) | — | (6 | ) | (4 | ) | 1 | (9 | ) | ||||||||||||||
Net Total Assets (Liabilities) | $ | 28 | $ | 12 | $ | 20 | $ | (4 | ) | $ | — | $ | 28 | |||||||||||
Total | Level 1 | Level 2 | Level 3 | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | Net Amount | |||||||||||||||||||
31-Dec-13 | ||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||
Cash Equivalents(1) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Restricted Cash(1) | 2 | 2 | — | — | — | 2 | ||||||||||||||||||
Rabbi Trust Investments(2) | 22 | — | 22 | — | — | 22 | ||||||||||||||||||
Energy Contracts - Regulatory Recovery(3) | 2 | — | 1 | 1 | (1 | ) | 1 | |||||||||||||||||
Total Assets | 26 | 2 | 23 | 1 | (1 | ) | 25 | |||||||||||||||||
Liabilities | ||||||||||||||||||||||||
Energy Contracts - Regulatory Recovery(3) | (2 | ) | — | — | (2 | ) | 1 | (1 | ) | |||||||||||||||
Energy Contracts - Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | |||||||||||||||
Interest Rate Swaps(4) | (7 | ) | — | (7 | ) | — | — | (7 | ) | |||||||||||||||
Total Liabilities | (10 | ) | — | (7 | ) | (3 | ) | 1 | (9 | ) | ||||||||||||||
Net Total Assets (Liabilities) | $ | 16 | $ | 2 | $ | 16 | $ | (2 | ) | $ | — | $ | 16 | |||||||||||
(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 balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets. | |||||||||||||||||||||||
(2) | Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets. | |||||||||||||||||||||||
(3) | Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below. | |||||||||||||||||||||||
(4) | Interest Rate Swaps still held are valued based on the 6-month London Interbank Offered Rate (LIBOR). An interest rate swap valued based on the Securities Industry and Financial Markets Association Municipal swap index matured in September 2014. These interest rate swaps are included in Derivative Instruments on the balance sheets. | |||||||||||||||||||||||
(5) | All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets. | |||||||||||||||||||||||
DERIVATIVE INSTRUMENTS | ||||||||||||||||||||||||
We enter into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with our gas and purchased power requirements. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC. | ||||||||||||||||||||||||
We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers. | ||||||||||||||||||||||||
For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, or industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe 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, we apply adjustments based on historical price curve relationships, transmission, and line losses. | ||||||||||||||||||||||||
We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. In the first half of 2013, we also used this pricing model to value our power options. | ||||||||||||||||||||||||
We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data. | ||||||||||||||||||||||||
The inputs and our 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. We review the assumptions underlying our price curves monthly. | ||||||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||||||
We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. The interest rate swap agreements expire through January 2020. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 11. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $2 million. | ||||||||||||||||||||||||
Financial Impact of Energy Contracts | ||||||||||||||||||||||||
We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables: | ||||||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities | $ | (6 | ) | $ | (1 | ) | $ | (4 | ) | $ | (2 | ) | ||||||||||||
Realized gains and losses on settled contracts are fully recoverable through the PPFAC. At September 30, 2014, we have energy contracts that will settle through the third quarter of 2017. | ||||||||||||||||||||||||
Derivative Volumes | ||||||||||||||||||||||||
The volumes associated with our energy contracts were as follows: | ||||||||||||||||||||||||
September 30, 2014 | December 31, 2013 | |||||||||||||||||||||||
Power Contracts GWh | 842 | 779 | ||||||||||||||||||||||
Gas Contracts GBtu | 20,595 | 9,615 | ||||||||||||||||||||||
Level 3 Fair Value Measurements | ||||||||||||||||||||||||
The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: | ||||||||||||||||||||||||
Fair Value at | ||||||||||||||||||||||||
Valuation | 30-Sep-14 | Range of | ||||||||||||||||||||||
Approach | Assets | Liabilities | Unobservable Inputs | Unobservable Input | ||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Forward Power Contracts | Market approach | $ | — | $ | (3 | ) | Market price per MWh | $ | 27.5 | $ | 43.5 | |||||||||||||
Gas Option Contracts | Option model | — | (1 | ) | Market price per MMbtu | $ | 3.67 | $ | 4.24 | |||||||||||||||
Gas volatility | 24.88 | % | 40.62 | % | ||||||||||||||||||||
Level 3 Energy Contracts | $ | — | $ | (4 | ) | |||||||||||||||||||
Fair Value at | ||||||||||||||||||||||||
Valuation | 31-Dec-13 | Range of | ||||||||||||||||||||||
Approach | Assets | Liabilities | Unobservable Inputs | Unobservable Input | ||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Forward Power Contracts | Market approach | $ | — | $ | (3 | ) | Market price per MWh | $ | 27 | $ | 48.25 | |||||||||||||
Gas Option Contracts | Option model | 1 | — | Market price per MMbtu | $ | 3.88 | $ | 4.32 | ||||||||||||||||
Gas volatility | 25.05 | % | 35.07 | % | ||||||||||||||||||||
Level 3 Energy Contracts | $ | 1 | $ | (3 | ) | |||||||||||||||||||
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 tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy: | ||||||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Balances at June 30 | $ | — | $ | (1 | ) | |||||||||||||||||||
Realized/Unrealized Gains/(Losses) Recorded to: | ||||||||||||||||||||||||
Net Regulatory Assets/Liabilities – Derivative Instruments | (4 | ) | (1 | ) | ||||||||||||||||||||
Settlements | — | — | ||||||||||||||||||||||
Balances at September 30 | $ | (4 | ) | $ | (2 | ) | ||||||||||||||||||
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period | $ | (2 | ) | $ | — | |||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Balances at December 31 | $ | (2 | ) | $ | — | |||||||||||||||||||
Realized/Unrealized Gains/(Losses) Recorded to: | ||||||||||||||||||||||||
Net Regulatory Assets/Liabilities – Derivative Instruments | (3 | ) | (2 | ) | ||||||||||||||||||||
Settlements | 1 | — | ||||||||||||||||||||||
Balances at September 30 | $ | (4 | ) | $ | (2 | ) | ||||||||||||||||||
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period | $ | (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. We enter into contracts for the physical delivery of energy and 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. | ||||||||||||||||||||||||
We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to the Regulated Utilities; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties. | ||||||||||||||||||||||||
We consider 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 allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts. | ||||||||||||||||||||||||
Material adverse changes could trigger credit risk-related contingent features. At September 30, 2014, the value of derivative instruments in a net liability position under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $17 million. At September 30, 2014 , TEP had no cash collateral posted and less than $1 million LOCs as credit enhancements with its counterparties and did not hold any collateral from its counterparties. The additional collateral to be posted if credit-risk contingent features were triggered would be $17 million. | ||||||||||||||||||||||||
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. We use the following methods and assumptions for estimating the fair value of our financial instruments: | ||||||||||||||||||||||||
• | The carrying amounts of our current maturities of long-term debt and amounts outstanding under our credit agreements approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below. | |||||||||||||||||||||||
• | For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 conducted in 2011. No impairment has been recorded as TEP expects to recover the full carrying value in retail rates. | |||||||||||||||||||||||
• | For Long-Term Debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our 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 carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following: | ||||||||||||||||||||||||
30-Sep-14 | 31-Dec-13 | |||||||||||||||||||||||
Fair Value | Carrying | Fair | Carrying | Fair | ||||||||||||||||||||
Hierarchy | Value | Value | Value | Value | ||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||
Investment in Lease Equity | Level 3 | $ | 36 | $ | 26 | $ | 36 | $ | 25 | |||||||||||||||
Liabilities: | ||||||||||||||||||||||||
Long-Term Debt | Level 2 | 1,372 | 1,444 | 1,223 | 1,214 | |||||||||||||||||||
INCOME_TAXES_Income_Tax_Expens
INCOME TAXES (Income Tax Expense) | 9 Months Ended | |||||||
Sep. 30, 2014 | ||||||||
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: | ||||||||
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Millions of Dollars | ||||||||
Federal Income Tax Expense at Statutory Rate | $ | 22 | $ | 36 | ||||
State Income Tax Expense, Net of Federal Deduction | 3 | 5 | ||||||
Federal/State Tax Credits | (2 | ) | (1 | ) | ||||
Other | 1 | (1 | ) | |||||
Total Federal and State Income Tax Expense | $ | 24 | $ | 39 | ||||
Nine Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Millions of Dollars | ||||||||
Federal Income Tax Expense at Statutory Rate | $ | 49 | $ | 48 | ||||
State Income Tax Expense, Net of Federal Deduction | 6 | 6 | ||||||
Federal/State Tax Credits | (4 | ) | (2 | ) | ||||
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset | — | (11 | ) | |||||
Other | 1 | 1 | ||||||
Total Federal and State Income Tax Expense | $ | 52 | $ | 42 | ||||
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset | ||||||||
Renewable energy assets are eligible for investment tax credits. We reduce the income tax basis of those qualifying assets by half of the related investment tax credit. Historically, the difference between the income tax basis of the assets and the book basis under GAAP was recorded as a deferred tax liability with an offsetting charge to income tax expense in the year the qualifying asset was placed in service. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated. |
RECLASSIFICATIONS_FROM_ACCUMUL
RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT | 9 Months Ended | ||||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||||
Statement of Comprehensive Income [Abstract] | ' | ||||||||||||||||||
RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT | ' | ||||||||||||||||||
RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT | |||||||||||||||||||
The reclassifications from Accumulated Other Comprehensive Income (AOCI) by component are as follows: | |||||||||||||||||||
Details About Accumulated Other Comprehensive Income Components | Amount Reclassified from Other Comprehensive Income | Affected Line Item in the Income Statement | |||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Thousands of Dollars | |||||||||||||||||||
Realized Losses on Cash Flow Hedges | |||||||||||||||||||
Interest Rate Swaps - Debt | $ | (291 | ) | $ | (296 | ) | $ | (882 | ) | $ | (871 | ) | Interest Expense Long-Term Debt | ||||||
Interest Rate Swaps - Capital Leases | (451 | ) | (612 | ) | (1,649 | ) | (1,820 | ) | Interest Expense Capital Leases | ||||||||||
Commodity Contracts | (478 | ) | (556 | ) | (621 | ) | (747 | ) | Purchased Energy/Purchased Power | ||||||||||
Income Tax Benefit | 546 | 579 | 1,238 | 1,360 | |||||||||||||||
Realized Losses on Cash Flow Hedges, Net of Taxes | (674 | ) | (885 | ) | (1,914 | ) | (2,078 | ) | |||||||||||
Amortization of SERP | |||||||||||||||||||
Prior Service Cost and Net Loss | (40 | ) | (110 | ) | (119 | ) | (332 | ) | Other Expense | ||||||||||
Income Tax Benefit | 15 | 42 | 45 | 127 | |||||||||||||||
Amortization, Net of Taxes | (25 | ) | (68 | ) | (74 | ) | (205 | ) | |||||||||||
Total Reclassifications from Other Comprehensive Income | $ | (699 | ) | $ | (953 | ) | $ | (1,988 | ) | $ | (2,283 | ) |
RECENTLY_ISSUED_ACCOUNTING_PRO
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS | 9 Months Ended |
Sep. 30, 2014 | |
Disclosure Text Block [Abstract] | ' |
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS | ' |
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS | |
In April 2014, the Financial Accounting Standards Board (FASB) issued an accounting standards update that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. This guidance will be effective in the first quarter of 2015. We do not expect the adoption of this guidance to have an impact on the presentation of our financial statements or our disclosures. | |
In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. We will be required to adopt the new guidance retrospectively for annual and interim periods beginning January 1, 2017; early adoption is not permitted. We are evaluating the impact to our financial statements and disclosures. | |
In August 2014, the FASB issued guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide related disclosures. This update is effective for annual and interim periods beginning January 1, 2017; early adoption is permitted. TEP does not expect the adoption of this guidance to have an impact on its disclosures. |
NATURE_OF_OPERATIONS_AND_FINAN1
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies) | 9 Months Ended | |
Sep. 30, 2014 | ||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' | |
Basis of Presentation | ' | |
BASIS OF PRESENTATION | ||
We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2013 Annual Report on Form 10-K. | ||
The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, our quarterly results are not indicative of annual operating results. | ||
TEP did not reflect the impacts of acquisition accounting in its financial statements. All adjustments of assets and liabilities to fair value and the resultant goodwill associated with the Merger were recorded by FortisUS Inc., a wholly owned subsidiary of Fortis. | ||
As a result of the Fortis Merger, TEP has elected to change its method of reporting cash flows from the direct to the indirect method to conform to the presentation method elected by Fortis. Certain amounts from prior periods have been reclassified to conform to the current period presentation. | ||
Revision of Prior Period Balance Sheets | ' | |
REVISION OF PRIOR PERIOD BALANCE SHEETS | ||
TEP revised its December 31, 2013 balance sheet to correct an error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. We do not believe the misclassification was material to the previously issued financial statements. | ||
Recently Adopted Accounting Pronouncements | ' | |
RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS | ||
In 2014, we adopted accounting guidance that: | ||
• | requires an entity to recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay and any additional amount the entity expects to pay on behalf of its co-obligors. The adoption of this guidance did not have a material impact on our disclosures, financial condition, results of operations, or cash flows. | |
• | impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows. |
RELATED_PARTY_TRANSACTIONS_REL1
RELATED PARTY TRANSACTIONS RELATED PARTY TRANSACTIONS (Table) | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Related Party Transactions [Abstract] | ' | |||||||||||||||
Schedule of Related Party Transactions | ' | |||||||||||||||
The following table summarizes related party transactions: | ||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Millions of Dollars | ||||||||||||||||
Wholesale Sales - TEP to UNS Electric (1) | $ | 2 | $ | — | $ | 3 | $ | 1 | ||||||||
Wholesale Sales - UNS Electric to TEP (1) | 2 | — | 3 | 1 | ||||||||||||
Control Area Services - TEP to UNS Electric (2) | 1 | 1 | 2 | 3 | ||||||||||||
Common Costs - TEP to UNS Energy Affiliates (3) | 3 | 3 | 10 | 9 | ||||||||||||
Supplemental Workforce - SES to TEP (4) | 4 | 4 | 12 | 11 | ||||||||||||
Corporate Services and Other Labor Charges - TEP to UNS Energy Affiliates (5) | 3 | 4 | 7 | 10 | ||||||||||||
Corporate Services - UNS Energy Affiliates to TEP (5) | — | — | 1 | 1 | ||||||||||||
(1) | TEP and UNS Electric sell power to each other at prevailing market prices. | |||||||||||||||
(2) | TEP charges UNS Electric for control area services under a FERC-accepted Control Area Services Agreement. | |||||||||||||||
(3) | Common costs (systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable. | |||||||||||||||
(4) | SES provides supplemental workforce and meter-reading services to TEP. Amounts are based on costs of services performed, and management believes that the charges for the services are reasonable. | |||||||||||||||
(5) | All Corporate Services (finance, accounting, tax, legal and information technology) and other labor services are directly assigned to the benefiting entity at a fully burdened cost when possible; other costs are allocated using the Massachusetts' Formula, an industry accepted method of allocating common costs to affiliated entities. | |||||||||||||||
At September 30, 2014 and December 31, 2013, our Balance Sheets include the following intercompany balances: | ||||||||||||||||
Balances at | ||||||||||||||||
30-Sep-14 | 31-Dec-13 | |||||||||||||||
Millions of Dollars | ||||||||||||||||
Receivables from Related Parties | ||||||||||||||||
UNS Electric | $ | 2 | $ | 3 | ||||||||||||
UNS Gas | 1 | 2 | ||||||||||||||
UNS Energy | — | 1 | ||||||||||||||
Total Due from Related Parties | $ | 3 | $ | 6 | ||||||||||||
Payables to Related Parties | ||||||||||||||||
SES | $ | 3 | $ | 2 | ||||||||||||
UNS Electric | 1 | — | ||||||||||||||
UNS Energy | — | 7 | ||||||||||||||
Total Due to Related Parties | $ | 4 | $ | 9 | ||||||||||||
COMMITMENTS_CONTINGENCIES_AND_1
COMMITMENTS. CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Tables) | 9 Months Ended | |||||||||||||||||||||||||||
Sep. 30, 2014 | ||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | |||||||||||||||||||||||||||
Commitments | ' | |||||||||||||||||||||||||||
In addition to those reported in our 2013 Annual Report on Form 10-K, TEP entered into the following long-term commitments through September 30, 2014: | ||||||||||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | Thereafter | Total | ||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||
Fuel, Including Transportation | $ | — | $ | 9 | $ | 9 | $ | 10 | $ | 10 | $ | 42 | $ | 80 | ||||||||||||||
Purchased Power | — | 18 | — | — | — | — | 18 | |||||||||||||||||||||
Renewable Power Purchase Agreements (PPA)(2) | 6 | 5 | 5 | 5 | 5 | 60 | 86 | |||||||||||||||||||||
Capital Lease Obligations(1) | — | 120 | — | — | — | — | 120 | |||||||||||||||||||||
Total Purchase Commitments | $ | 6 | $ | 152 | $ | 14 | $ | 15 | $ | 15 | $ | 102 | $ | 304 | ||||||||||||||
(1) | In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 4. | |||||||||||||||||||||||||||
(2) | In July 2014, TEP entered into a 20-year PPA with a renewable energy generation facility that achieved commercial operation in July 2014. TEP is obligated to purchase 100% of the output from this facility. The amounts in the table also reflect updated estimated annual production for existing contracts which increased the minimum annual payment obligations. | |||||||||||||||||||||||||||
Schedule of Mercury Emission Control Costs | ' | |||||||||||||||||||||||||||
TEP's share of the estimated costs to comply with the MATS rules includes the following: | ||||||||||||||||||||||||||||
Estimated Mercury Emissions Control Costs: | Navajo | Springerville(1) | ||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||
Capital Expenditures | $ | 1 | $ | 5 | ||||||||||||||||||||||||
Annual O&M Expenses | 1 | 1 | ||||||||||||||||||||||||||
(1) | Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2. | |||||||||||||||||||||||||||
Regional Haze Rules, Schedule of Environmental Loss Contingencies by Site | ' | |||||||||||||||||||||||||||
TEP cannot predict the ultimate outcome of these matters. | ||||||||||||||||||||||||||||
TEP's estimated costs involved in meeting these rules are: | ||||||||||||||||||||||||||||
Estimated NOx Emissions Control Costs: | Navajo (1) | San Juan (2) | Four Corners (3) | Sundt (4) | ||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||
Capital Expenditures | $ | 42 | $ | 35 | $ | 35 | $ | 12 | ||||||||||||||||||||
Annual O&M Expenses | 1 | 1 | 2 | 6-May | ||||||||||||||||||||||||
-1 | In August 2014, the EPA published a final rule approving a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year. | |||||||||||||||||||||||||||
-2 | In October 2014, the EPA published a final rule approving a state plan covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016. Corresponding to that action, the EPA withdrew the previously applicable FIP addressing the same requirements. Prior to the shutdown of any units in San Juan, PNM must obtain New Mexico Public Regulation Commission approval. If Unit 2 is retired early, TEP expects to request ACC approval to recover all costs associated with the early closure of the unit. TEP owns 50% of San Juan Unit 2. At September 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $111 million. | |||||||||||||||||||||||||||
-3 | In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5. | |||||||||||||||||||||||||||
(4) In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At September 30, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover all the remaining costs of the coal handling facilities. |
EMPLOYEE_BENEFIT_PLANS_Tables
EMPLOYEE BENEFIT PLANS (Tables) | 9 Months Ended | |||||||||||||||
Sep. 30, 2014 | ||||||||||||||||
Text Block [Abstract] | ' | |||||||||||||||
Components of Net Periodic Benefit Cost | ' | |||||||||||||||
Net periodic benefit plan cost includes the following components: | ||||||||||||||||
Pension Benefits | Other Retiree Benefits | |||||||||||||||
Three Months Ended September 30, | ||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Millions of Dollars | ||||||||||||||||
Service Cost | $ | 2 | $ | 3 | $ | 1 | $ | 1 | ||||||||
Interest Cost | 4 | 4 | — | — | ||||||||||||
Expected Return on Plan Assets | (5 | ) | (5 | ) | — | — | ||||||||||
Actuarial Loss Amortization | 1 | 2 | — | — | ||||||||||||
Net Periodic Benefit Cost | $ | 2 | $ | 4 | $ | 1 | $ | 1 | ||||||||
Pension Benefits | Other Retiree Benefits | |||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Millions of Dollars | ||||||||||||||||
Service Cost | $ | 7 | $ | 8 | $ | 3 | $ | 3 | ||||||||
Interest Cost | 12 | 11 | 2 | 2 | ||||||||||||
Expected Return on Plan Assets | (16 | ) | (14 | ) | (1 | ) | (1 | ) | ||||||||
Actuarial Loss Amortization | 3 | 6 | — | — | ||||||||||||
Net Periodic Benefit Cost | $ | 6 | $ | 11 | $ | 4 | $ | 4 | ||||||||
FAIR_VALUE_MEASUREMENTS_AND_DE1
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables) | 9 Months Ended | |||||||||||||||||||||||
Sep. 30, 2014 | ||||||||||||||||||||||||
Disclosure Text Block [Abstract] | ' | |||||||||||||||||||||||
Schedule of Fair Value Measurements of Financial Assets and Liabilities | ' | |||||||||||||||||||||||
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. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. | ||||||||||||||||||||||||
Total | Level 1 | Level 2 | Level 3 | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | Net Amount | |||||||||||||||||||
30-Sep-14 | ||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||
Cash Equivalents(1) | $ | 10 | $ | 10 | $ | — | $ | — | $ | — | $ | 10 | ||||||||||||
Restricted Cash(1) | 2 | 2 | — | — | — | 2 | ||||||||||||||||||
Rabbi Trust Investments(2) | 25 | — | 25 | — | — | 25 | ||||||||||||||||||
Energy Contracts - Regulatory Recovery(3) | 1 | — | 1 | — | (1 | ) | — | |||||||||||||||||
Total Assets | 38 | 12 | 26 | — | (1 | ) | 37 | |||||||||||||||||
Liabilities | ||||||||||||||||||||||||
Energy Contracts - Regulatory Recovery(3) | (5 | ) | — | (2 | ) | (3 | ) | 1 | (4 | ) | ||||||||||||||
Energy Contracts - Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | |||||||||||||||
Interest Rate Swaps(4) | (4 | ) | — | (4 | ) | — | — | (4 | ) | |||||||||||||||
Total Liabilities | (10 | ) | — | (6 | ) | (4 | ) | 1 | (9 | ) | ||||||||||||||
Net Total Assets (Liabilities) | $ | 28 | $ | 12 | $ | 20 | $ | (4 | ) | $ | — | $ | 28 | |||||||||||
Total | Level 1 | Level 2 | Level 3 | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | Net Amount | |||||||||||||||||||
31-Dec-13 | ||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||
Cash Equivalents(1) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
Restricted Cash(1) | 2 | 2 | — | — | — | 2 | ||||||||||||||||||
Rabbi Trust Investments(2) | 22 | — | 22 | — | — | 22 | ||||||||||||||||||
Energy Contracts - Regulatory Recovery(3) | 2 | — | 1 | 1 | (1 | ) | 1 | |||||||||||||||||
Total Assets | 26 | 2 | 23 | 1 | (1 | ) | 25 | |||||||||||||||||
Liabilities | ||||||||||||||||||||||||
Energy Contracts - Regulatory Recovery(3) | (2 | ) | — | — | (2 | ) | 1 | (1 | ) | |||||||||||||||
Energy Contracts - Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | |||||||||||||||
Interest Rate Swaps(4) | (7 | ) | — | (7 | ) | — | — | (7 | ) | |||||||||||||||
Total Liabilities | (10 | ) | — | (7 | ) | (3 | ) | 1 | (9 | ) | ||||||||||||||
Net Total Assets (Liabilities) | $ | 16 | $ | 2 | $ | 16 | $ | (2 | ) | $ | — | $ | 16 | |||||||||||
(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 balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets. | |||||||||||||||||||||||
(2) | Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets. | |||||||||||||||||||||||
(3) | Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below. | |||||||||||||||||||||||
(4) | Interest Rate Swaps still held are valued based on the 6-month London Interbank Offered Rate (LIBOR). An interest rate swap valued based on the Securities Industry and Financial Markets Association Municipal swap index matured in September 2014. These interest rate swaps are included in Derivative Instruments on the balance sheets. | |||||||||||||||||||||||
(5) | All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets. | |||||||||||||||||||||||
Financial Impact of Energy Contracts | ' | |||||||||||||||||||||||
We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables: | ||||||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities | $ | (6 | ) | $ | (1 | ) | $ | (4 | ) | $ | (2 | ) | ||||||||||||
Realized gains and losses on settled contracts are fully recoverable through the PPFAC. At September 30, 2014, we have energy contracts that will settle through the third quarter of 2017. | ||||||||||||||||||||||||
Derivative Volumes | ' | |||||||||||||||||||||||
The volumes associated with our energy contracts were as follows: | ||||||||||||||||||||||||
September 30, 2014 | December 31, 2013 | |||||||||||||||||||||||
Power Contracts GWh | 842 | 779 | ||||||||||||||||||||||
Gas Contracts GBtu | 20,595 | 9,615 | ||||||||||||||||||||||
Quantitative Information Regarding Unobservable Inputs | ' | |||||||||||||||||||||||
The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: | ||||||||||||||||||||||||
Fair Value at | ||||||||||||||||||||||||
Valuation | 30-Sep-14 | Range of | ||||||||||||||||||||||
Approach | Assets | Liabilities | Unobservable Inputs | Unobservable Input | ||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Forward Power Contracts | Market approach | $ | — | $ | (3 | ) | Market price per MWh | $ | 27.5 | $ | 43.5 | |||||||||||||
Gas Option Contracts | Option model | — | (1 | ) | Market price per MMbtu | $ | 3.67 | $ | 4.24 | |||||||||||||||
Gas volatility | 24.88 | % | 40.62 | % | ||||||||||||||||||||
Level 3 Energy Contracts | $ | — | $ | (4 | ) | |||||||||||||||||||
Fair Value at | ||||||||||||||||||||||||
Valuation | 31-Dec-13 | Range of | ||||||||||||||||||||||
Approach | Assets | Liabilities | Unobservable Inputs | Unobservable Input | ||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Forward Power Contracts | Market approach | $ | — | $ | (3 | ) | Market price per MWh | $ | 27 | $ | 48.25 | |||||||||||||
Gas Option Contracts | Option model | 1 | — | Market price per MMbtu | $ | 3.88 | $ | 4.32 | ||||||||||||||||
Gas volatility | 25.05 | % | 35.07 | % | ||||||||||||||||||||
Level 3 Energy Contracts | $ | 1 | $ | (3 | ) | |||||||||||||||||||
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. | ||||||||||||||||||||||||
Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities | ' | |||||||||||||||||||||||
The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy: | ||||||||||||||||||||||||
Three Months Ended September 30, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Balances at June 30 | $ | — | $ | (1 | ) | |||||||||||||||||||
Realized/Unrealized Gains/(Losses) Recorded to: | ||||||||||||||||||||||||
Net Regulatory Assets/Liabilities – Derivative Instruments | (4 | ) | (1 | ) | ||||||||||||||||||||
Settlements | — | — | ||||||||||||||||||||||
Balances at September 30 | $ | (4 | ) | $ | (2 | ) | ||||||||||||||||||
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period | $ | (2 | ) | $ | — | |||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Balances at December 31 | $ | (2 | ) | $ | — | |||||||||||||||||||
Realized/Unrealized Gains/(Losses) Recorded to: | ||||||||||||||||||||||||
Net Regulatory Assets/Liabilities – Derivative Instruments | (3 | ) | (2 | ) | ||||||||||||||||||||
Settlements | 1 | — | ||||||||||||||||||||||
Balances at September 30 | $ | (4 | ) | $ | (2 | ) | ||||||||||||||||||
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period | $ | (2 | ) | $ | (1 | ) | ||||||||||||||||||
Balance Sheets Carrying Value Estimated Fair Values of Financial Instruments | ' | |||||||||||||||||||||||
The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following: | ||||||||||||||||||||||||
30-Sep-14 | 31-Dec-13 | |||||||||||||||||||||||
Fair Value | Carrying | Fair | Carrying | Fair | ||||||||||||||||||||
Hierarchy | Value | Value | Value | Value | ||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||
Investment in Lease Equity | Level 3 | $ | 36 | $ | 26 | $ | 36 | $ | 25 | |||||||||||||||
Liabilities: | ||||||||||||||||||||||||
Long-Term Debt | Level 2 | 1,372 | 1,444 | 1,223 | 1,214 | |||||||||||||||||||
INCOME_TAXES_Tables
INCOME TAXES (Tables) | 9 Months Ended | |||||||
Sep. 30, 2014 | ||||||||
Income Tax Disclosure [Abstract] | ' | |||||||
Schedule of Effective Income Tax Rate Reconciliation | ' | |||||||
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: | ||||||||
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Millions of Dollars | ||||||||
Federal Income Tax Expense at Statutory Rate | $ | 22 | $ | 36 | ||||
State Income Tax Expense, Net of Federal Deduction | 3 | 5 | ||||||
Federal/State Tax Credits | (2 | ) | (1 | ) | ||||
Other | 1 | (1 | ) | |||||
Total Federal and State Income Tax Expense | $ | 24 | $ | 39 | ||||
Nine Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Millions of Dollars | ||||||||
Federal Income Tax Expense at Statutory Rate | $ | 49 | $ | 48 | ||||
State Income Tax Expense, Net of Federal Deduction | 6 | 6 | ||||||
Federal/State Tax Credits | (4 | ) | (2 | ) | ||||
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset | — | (11 | ) | |||||
Other | 1 | 1 | ||||||
Total Federal and State Income Tax Expense | $ | 52 | $ | 42 | ||||
RECLASSIFICATIONS_FROM_ACCUMUL1
RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT (Tables) | 9 Months Ended | ||||||||||||||||||
Sep. 30, 2014 | |||||||||||||||||||
Statement of Comprehensive Income [Abstract] | ' | ||||||||||||||||||
Reclassifications from Other Comprehensive Income | ' | ||||||||||||||||||
The reclassifications from Accumulated Other Comprehensive Income (AOCI) by component are as follows: | |||||||||||||||||||
Details About Accumulated Other Comprehensive Income Components | Amount Reclassified from Other Comprehensive Income | Affected Line Item in the Income Statement | |||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Thousands of Dollars | |||||||||||||||||||
Realized Losses on Cash Flow Hedges | |||||||||||||||||||
Interest Rate Swaps - Debt | $ | (291 | ) | $ | (296 | ) | $ | (882 | ) | $ | (871 | ) | Interest Expense Long-Term Debt | ||||||
Interest Rate Swaps - Capital Leases | (451 | ) | (612 | ) | (1,649 | ) | (1,820 | ) | Interest Expense Capital Leases | ||||||||||
Commodity Contracts | (478 | ) | (556 | ) | (621 | ) | (747 | ) | Purchased Energy/Purchased Power | ||||||||||
Income Tax Benefit | 546 | 579 | 1,238 | 1,360 | |||||||||||||||
Realized Losses on Cash Flow Hedges, Net of Taxes | (674 | ) | (885 | ) | (1,914 | ) | (2,078 | ) | |||||||||||
Amortization of SERP | |||||||||||||||||||
Prior Service Cost and Net Loss | (40 | ) | (110 | ) | (119 | ) | (332 | ) | Other Expense | ||||||||||
Income Tax Benefit | 15 | 42 | 45 | 127 | |||||||||||||||
Amortization, Net of Taxes | (25 | ) | (68 | ) | (74 | ) | (205 | ) | |||||||||||
Total Reclassifications from Other Comprehensive Income | $ | (699 | ) | $ | (953 | ) | $ | (1,988 | ) | $ | (2,283 | ) |
NATURE_OF_OPERATIONS_AND_FINAN2
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION Nature of Operations (Details) | 9 Months Ended |
Sep. 30, 2014 | |
sqmi | |
customer | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' |
Entity Number Of Customers | 415,000 |
Area In Which Subsidiary Generates Transmits And Distributes Electricity To Retail Electric Customers | 1,155 |
NATURE_OF_OPERATIONS_AND_FINAN3
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION Fortis Acquisition of UNS Energy (Details) (USD $) | 9 Months Ended | ||||||
In Millions, except Per Share data, unless otherwise specified | Sep. 30, 2014 | Aug. 15, 2014 | Oct. 10, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Aug. 15, 2014 |
Subsequent Event [Member] | Total Bill Credit Refunds Over 5 Years [Member] | Bill Credit Refunds in Year 1 [Member] | Annual Bill Credit Refunds in Years 2 Through 5 [Member] | Fortis Inc. [Member] | |||
Business Acquisition [Line Items] | ' | ' | ' | ' | ' | ' | ' |
Business Acquisition, Share Price | ' | ' | ' | ' | ' | ' | $60.25 |
Fortis Acquisition Direct Customer Benefit | ' | ' | ' | $19 | $6 | $3 | ' |
years over which customer benefits are to be paid | ' | ' | ' | 5 | ' | ' | ' |
Portion of Net Income Entity can Dividend to Parent | 60.00% | ' | ' | ' | ' | ' | ' |
Length in Periods of Restrictions On Payment Of Dividends (in Years) | 5 | ' | ' | ' | ' | ' | ' |
Required Equity Capitalization for Regulated Utilities Prior to Dividend Payment | 50.00% | ' | ' | ' | ' | ' | ' |
Required Equity Investment By Acquiring Company Per Merger Settlement Agreement Subject to Regulatory Approval | ' | 220 | ' | ' | ' | ' | ' |
Initial Equity Investment By Acquiring Company To Parent of Filer | ' | 37 | ' | ' | ' | ' | ' |
Additional post merger equity contribution to parent of entity | ' | ' | 200 | ' | ' | ' | ' |
Proceeds from Contributions from Parent | ' | ' | 175 | ' | ' | ' | ' |
Merger-Related Costs Recorded through Closing of Merger | $15 | ' | ' | ' | ' | ' | ' |
NATURE_OF_OPERATIONS_AND_FINAN4
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION Share-Based Compensation Expense (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Share-based Compensation [Abstract] | ' | ' | ' | ' |
Share Based Comp Accelerated Vesting Expense | $2 | ' | ' | ' |
Total share-based compensation expense | $4 | $1 | $5 | $3 |
NATURE_OF_OPERATIONS_AND_FINAN5
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION Revision of Prior Period Balance Sheets (Detail) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2013 |
Deferred Income Taxes Current And Noncurrent [Member] | ' |
Quantifying Misstatement in Current Year Financial Statements, Amount | $7 |
Capital Lease Obligation Current And Noncurrent [Member] | ' |
Quantifying Misstatement in Current Year Financial Statements, Amount | $18 |
REGULATORY_MATTERS_COST_RECOVE
REGULATORY MATTERS COST RECOVERY MECHANISMS (Details) (USD $) | 1 Months Ended | 9 Months Ended | 10 Months Ended | 1 Months Ended | 12 Months Ended | |||
Aug. 31, 2014 | 31-May-14 | Sep. 30, 2014 | Sep. 30, 2013 | Apr. 30, 2014 | Apr. 30, 2014 | Apr. 30, 2014 | Dec. 31, 2014 | |
May Through September 2014 [Member] | October 2014 Through March 2015 [Member] | Scenario, Forecast [Member] | ||||||
Schedule of Regulatory Cost Recovery Mechanisms [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
Purchased Power And Fuel Adjustment Clause Rate | ' | ' | ' | ' | 0.0014 | 0.001 | 0.005 | ' |
Mine Fire Cost Deferral | ' | ' | $10,000,000 | ' | ' | ' | ' | ' |
Mine Fire Insurance Settlement Proceeds | ' | ' | 8,000,000 | ' | ' | ' | ' | ' |
Environmental Compliance Adjustor Rate | ' | 0.000049 | ' | ' | ' | ' | ' | ' |
Regulated Operating Revenue, Other | ' | ' | ' | ' | ' | ' | ' | 1,000,000 |
Energy Efficiency Performance Incentive | ' | ' | 2,000,000 | ' | ' | ' | ' | ' |
Cap on increase in lost fixed cost recovery rate | ' | ' | 1.00% | ' | ' | ' | ' | ' |
Revenue Recognized Under Lost Fixed Cost Recovery Mechanism | ' | ' | 8,350,000 | 0 | ' | ' | ' | ' |
Lost Fixed Cost Recovery Requested | ' | $5,000,000 | ' | ' | ' | ' | ' | ' |
LFCR Rate, Retail Revenue for EE | 0.41% | ' | ' | ' | ' | ' | ' | ' |
LFCR Rate, Retail Revenue for Distributed Generation | 0.31% | ' | ' | ' | ' | ' | ' | ' |
RELATED_PARTY_TRANSACTIONS_REL2
RELATED PARTY TRANSACTIONS RELATED PARTY TRANSACTIONS (Details) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | Tucson Electric Power Company To Uns Electric [Member] | Tucson Electric Power Company To Uns Electric [Member] | Tucson Electric Power Company To Uns Electric [Member] | Tucson Electric Power Company To Uns Electric [Member] | Uns Electric To Tucson Electric Power Company [Member] | Uns Electric To Tucson Electric Power Company [Member] | Uns Electric To Tucson Electric Power Company [Member] | Uns Electric To Tucson Electric Power Company [Member] | TEP to UNS Energy Affiliates [Member] | TEP to UNS Energy Affiliates [Member] | TEP to UNS Energy Affiliates [Member] | TEP to UNS Energy Affiliates [Member] | Southwest Energy Solutions, Inc. to TEP [Member] | Southwest Energy Solutions, Inc. to TEP [Member] | Southwest Energy Solutions, Inc. to TEP [Member] | Southwest Energy Solutions, Inc. to TEP [Member] | UNS Energy Affiliates to TEP [Member] | UNS Energy Affiliates to TEP [Member] | UNS Energy Affiliates to TEP [Member] | UNS Energy Affiliates to TEP [Member] | UNS Electric [Member] | UNS Electric [Member] | Uns Gas [Member] | Uns Gas [Member] | Uns Energy Corporation [Member] | Uns Energy Corporation [Member] | Southwest Energy Solutions, Inc. [Member] | Southwest Energy Solutions, Inc. [Member] | ||
Related Party Transaction [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Wholesale Sales from Related Parties | ' | ' | $2 | $0 | $3 | $1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Wholesale Purchases from Related Parties | ' | ' | ' | ' | ' | ' | 2 | 0 | 3 | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Control Area Services, Other Revenues from Transactions with Related Parties | ' | ' | 1 | 1 | 2 | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common Costs Charged to Related Parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 3 | 10 | 9 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Supplemental Workforce, Maintenance Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4 | 4 | 12 | 11 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Corporate Services and Other Labor Charges | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 4 | 7 | 10 | ' | ' | ' | ' | 0 | 0 | 1 | 1 | ' | ' | ' | ' | ' | ' | ' | ' |
Related Party Transaction, Due from (to) Related Parties [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Receivable from Related Parties | 3 | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | 3 | 1 | 2 | 0 | 1 | ' | ' |
Payable to Related Parties | $4 | $9 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1 | $0 | ' | ' | $0 | $7 | $3 | $2 |
DEBT_AND_CAPITAL_LEASE_OBLIGAT1
DEBT AND CAPITAL LEASE OBLIGATIONS (Capital Leases) (Details) (Springerville Coal Handling Facilities Lease [Member], USD $) | 1 Months Ended | ||
In Millions, unless otherwise specified | Apr. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 |
SRP [Member] | Tri-State [Member] | ||
Capital Lease Asset Purchase Commitment [Line Items] | ' | ' | ' |
Increase in Capital Lease Obligation | $109 | ' | ' |
Fixed price to acquire leased interest in facilities | 120 | ' | ' |
Increase in utility plant under capital lease | 109 | ' | ' |
Sales Price of Leased Interest In Facilities | ' | $24 | $24 |
DEBT_AND_CAPITAL_LEASE_OBLIGAT2
DEBT AND CAPITAL LEASE OBLIGATIONS (Debt) (Detail) (USD $) | 9 Months Ended | 1 Months Ended | ||||||
Sep. 30, 2014 | Sep. 30, 2013 | Mar. 31, 2014 | Mar. 31, 2013 | Mar. 31, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Oct. 20, 2014 | |
Unsecured Debt [Member] | Unsecured Debt [Member] | Revolving Credit Facility [Member] | Revolving Credit Facility [Member] | Letter of Credit [Member] | Subsequent Event [Member] | |||
Revolving Credit Facility [Member] | ||||||||
Debt Instrument [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Face amount | ' | ' | $150,000,000 | $91,000,000 | ' | ' | ' | ' |
Fixed interest rate of long-term debt | ' | ' | 5.00% | ' | ' | ' | ' | ' |
Repayment of outstanding credit facility | 155,000,000 | 78,000,000 | ' | ' | 90,000,000 | ' | ' | ' |
Line of Credit Facility, Maximum Borrowing Capacity | ' | ' | ' | ' | ' | 200,000,000 | 81,590,000 | ' |
Line of Credit Facility, Remaining Borrowing Capacity | ' | ' | ' | ' | ' | 149,000,000 | ' | 185,000,000 |
Letters of Credit Outstanding, Amount | $1,000,000 | ' | ' | ' | ' | ' | $15,000,000 | ' |
COMMITMENTS_CONTINGENCIES_AND_2
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS COMMITMENTS (Details) (USD $) | Sep. 30, 2014 | |
In Millions, unless otherwise specified | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ' | |
2014 | $6 | |
2015 | 152 | |
2016 | 14 | |
2017 | 15 | |
2018 | 15 | |
Thereafter | 102 | |
Total | 304 | |
Springerville Coal Handling Facilities Lease [Member] | ' | |
Unrecorded Unconditional Purchase Obligation [Line Items] | ' | |
2014 | 0 | [1] |
2015 | 120 | [1] |
2016 | 0 | [1] |
2017 | 0 | [1] |
2018 | 0 | [1] |
Thereafter | 0 | [1] |
Total | 120 | [1] |
Fuel, Including Transportation | ' | |
Unrecorded Unconditional Purchase Obligation [Line Items] | ' | |
2014 | 0 | |
2015 | 9 | |
2016 | 9 | |
2017 | 10 | |
2018 | 10 | |
Thereafter | 42 | |
Total | 80 | |
Purchased Power | ' | |
Unrecorded Unconditional Purchase Obligation [Line Items] | ' | |
2014 | 0 | |
2015 | 18 | |
2016 | 0 | |
2017 | 0 | |
2018 | 0 | |
Thereafter | 0 | |
Total | 18 | |
Renewable Power Purchase Agreements (PPA)(2) | ' | |
Unrecorded Unconditional Purchase Obligation [Line Items] | ' | |
2014 | 6 | [2] |
2015 | 5 | [2] |
2016 | 5 | [2] |
2017 | 5 | [2] |
2018 | 5 | [2] |
Thereafter | 60 | [2] |
Total | $86 | [2] |
Duration of Contract Obligation in Year | 20 | |
Percentage of Purchase Power Obligations | 100.00% | |
[1] | (1)Â In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 4. | |
[2] | (2)Â In July 2014, TEP entered into a 20-year PPA with a renewable energy generation facility that achieved commercial operation in July 2014. TEP is obligated to purchase 100% of the output from this facility. The amounts in the table also reflect updated estimated annual production for existing contracts which increased the minimum annual payment obligations. |
COMMITMENTS_CONTINGENCIES_AND_3
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS CONTINGENCIES (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | Sep. 30, 2014 | Sep. 30, 2014 | Dec. 31, 2012 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 | Sep. 30, 2014 |
San Juan [Member] | Four Corner [Member] | Tucson to Nogales [Member] | Tucson to Nogales [Member] | Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member] | Tucson Electric Power Company's Share of Surface Mine Possible Additional Royalty Assessment [Member] | Assessment for Coal Severance Tax, Coal Supplier [Member] | Tucson Electric Power Company's Share of Assessment for Coal Severance Tax [Member] | |||
mi | San Juan [Member] | San Juan [Member] | Four Corner [Member] | Four Corner [Member] | ||||||
Commitments And Contingencies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percentage of ownership in generating station | ' | ' | 50.00% | 7.00% | ' | ' | ' | ' | ' | ' |
Percentage Of Ownership In Generating Units | ' | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' |
Estimate of Possible Loss Contingency | ' | ' | ' | ' | ' | ' | $5,000,000 | $1,000,000 | $30,000,000 | $1,000,000 |
TEP accrued an estimated loss related to Four Corners Generating Station | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' |
TEP's share of reclamation costs at expiration dates of the coal supply agreements | 44,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
TEP's recorded obligations for final mine reclamation costs | 21,000,000 | 18,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Transmission line from Tucson to Nogales | ' | ' | ' | ' | ' | 60 | ' | ' | ' | ' |
Transmission Line, in KV | ' | ' | ' | ' | ' | 345 | ' | ' | ' | ' |
Asset Impairment Charges | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' |
Regulatory Assets | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' |
Share of Defaulting Participants' Payment | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
COMMITMENTS_CONTINGENCIES_AND_4
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS ENVIRONMENTAL MATTERS (Detail) (USD $) | 9 Months Ended | |
Sep. 30, 2014 | ||
Navajo [Member] | ' | |
Commitments And Contingencies [Line Items] | ' | |
Estimated Future Capital Cost For Mercury Emission Control Equipment | $1,000,000 | |
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment | 1,000,000 | |
Estimated Capital Expenditure for Selective Catalytic Reduction | 42,000,000 | [1] |
Estimated Future Change in Operating Cost for Selective Catalytic Reduction | 1,000,000 | |
Better Than BART Agreement Year by which to Shut Down One Unit | '2020 | |
Better than BART Agreement, Year by which SCR Technology to be Installed | '2030 | |
Better than BART Agreement, Year by which Coal Fired Operation will Cease | '2044 | |
Estimated Capital Expenditure Related to Installation of Baghouses | 43,000,000 | |
Estimated Future Annual Operating Costs For Mercury Emission Control Equipment and Baghouses | 1,000,000 | |
Jointly Owned Utility Plant, Proportionate Ownership Share | 7.50% | |
Four Corner [Member] | ' | |
Commitments And Contingencies [Line Items] | ' | |
Estimated Capital Expenditure for Selective Catalytic Reduction | 35,000,000 | [2] |
Estimated Future Change in Operating Cost for Selective Catalytic Reduction | 2,000,000 | |
Jointly Owned Utility Plant, Proportionate Ownership Share | 7.00% | |
Springerville [Member] | ' | |
Commitments And Contingencies [Line Items] | ' | |
Estimated Future Capital Cost For Mercury Emission Control Equipment | 5,000,000 | [3] |
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment | 1,000,000 | [3] |
Percentage of Interest Committed to Purchase | 0.495 | |
Third-Party Participating in Ownership Interest | 50.50% | |
TEP's Share (in Percentage) of Obligations for Environmental Costs | 100.00% | |
San Juan [Member] | ' | |
Commitments And Contingencies [Line Items] | ' | |
Estimated Capital Expenditure for Selective Non Catalytic Reduction | 35,000,000 | [4] |
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction | 1,000,000 | |
Jointly Owned Utility Plant, Proportionate Ownership Share | 50.00% | |
Jointly Owned Utility Plant, Net Ownership Amount | 111,000,000 | |
Sundt [Member] | ' | |
Commitments And Contingencies [Line Items] | ' | |
Estimated Capital Expenditure for Monitoring Equipment | 1,000,000 | |
Estimated Capital Expenditure for Selective Non Catalytic Reduction | 12,000,000 | [5] |
Jointly Owned Utility Plant, Net Ownership Amount | 17,000,000 | |
Sundt [Member] | Minimum [Member] | ' | |
Commitments And Contingencies [Line Items] | ' | |
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction | 5,000,000 | |
Sundt [Member] | Maximum [Member] | ' | |
Commitments And Contingencies [Line Items] | ' | |
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction | $6,000,000 | |
[1] | he EPA published a final rule approving a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year. | |
[2] | In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5. | |
[3] | Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2. | |
[4] | In October 2014, the EPA published a final rule approving a state plan covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016. Corresponding to that action, the EPA withdrew the previously applicable FIP addressing the same requirements. Prior to the shutdown of any units in San Juan, PNM must obtain New Mexico Public Regulation Commission approval. If Unit 2 is retired early, TEP expects to request ACC approval to recover all costs associated with the early closure of the unit. TEP owns 50% of San Juan Unit 2. At September 30, 2014, the net book value of TEP's share in San Juan Unit 2 was $111 million. | |
[5] | In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At September 30, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover all the remaining costs of the coal handling facilities. |
PLANNED_PURCHASE_OF_GASFIRED_G1
PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY (Additional Information) (Details) (Entegra, Gila River Generating Station Unit 3 [Member], USD $) | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 30, 2014 |
In Millions, unless otherwise specified | MW | TUCSON ELECTRIC POWER COMPANY | UNS Electric [Member] | Letter of Credit [Member] |
MW | MW | |||
Unusual or Infrequent Item [Line Items] | ' | ' | ' | ' |
Planned Purchase of Gas-Fired Generation Facility | $219 | $164 | $55 | ' |
Generating capacity of plant in MW | 550 | 413 | 137 | ' |
Percentage of ownership in Generating Unit | ' | 75.00% | 25.00% | ' |
Guaranty Liabilities | ' | ' | ' | $15 |
EMPLOYEE_BENEFIT_PLANS_Compone
EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Pension Benefits [Member] | ' | ' | ' | ' |
Components of Net Periodic Benefit Plan Cost | ' | ' | ' | ' |
Service Cost | $2 | $3 | $7 | $8 |
Interest Cost | 4 | 4 | 12 | 11 |
Expected Return on Plan Assets | -5 | -5 | -16 | -14 |
Amortization of Actuarial (Gain) Loss | 1 | 2 | 3 | 6 |
Net Periodic Benefit Plan Cost | 2 | 4 | 6 | 11 |
Other Retiree Benefits [Member] | ' | ' | ' | ' |
Components of Net Periodic Benefit Plan Cost | ' | ' | ' | ' |
Service Cost | 1 | 1 | 3 | 3 |
Interest Cost | 0 | 0 | 2 | 2 |
Expected Return on Plan Assets | 0 | 0 | -1 | -1 |
Amortization of Actuarial (Gain) Loss | 0 | 0 | 0 | 0 |
Net Periodic Benefit Plan Cost | $1 | $1 | $4 | $4 |
Effects_of_Dilutive_Common_Sto
(Effects of Dilutive Common Stock on Weighted-Average Number of Shares) (Detail) (USD $) | 9 Months Ended | |
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 |
Numerator: | ' | ' |
Net Income | $87,541 | $96,433 |
SUPPLEMENTAL_CASH_FLOW_INFORMA1
SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) (USD $) | Mar. 31, 2014 | Mar. 31, 2013 | Aug. 31, 2013 | Apr. 30, 2014 |
Unsecured Debt [Member] | Unsecured Debt [Member] | Springerville Unit One Lease [Member] | Springerville Coal Handling Facilities Lease [Member] | |
Increase in Utility Plant under Capital Lease | ' | ' | $39,000,000 | $109,000,000 |
Debt Instrument, Face amount | 150,000,000 | 91,000,000 | ' | ' |
Increase in Capital Lease Obligation | ' | ' | $39,000,000 | $109,000,000 |
FAIR_VALUE_MEASUREMENTS_AND_DE2
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Assets | ' | ' | ||
Cash Equivalent | $10 | [1] | $0 | [1] |
Restricted Cash | 2 | [1] | 2 | [1] |
Rabbi Trust Investments to Support the Deferred Compensation and SERP | 25 | [2] | 22 | [2] |
Total Assets | 38 | 26 | ||
Liabilities | ' | ' | ||
Liabilities | -10 | -10 | ||
Net Total Assets (Liability) | 28 | 16 | ||
Energy Contracts [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | -5 | -2 | ||
Energy Contracts Cash Flow Hedge [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | -1 | -1 | ||
Interest Rate Swap [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | -4 | -7 | ||
Energy Contracts [Member] | ' | ' | ||
Assets | ' | ' | ||
Derivative Assets | 1 | [3] | 2 | [3] |
Level 1 [Member] | ' | ' | ||
Assets | ' | ' | ||
Cash Equivalent | 10 | [1] | 0 | [1] |
Restricted Cash | 2 | [1] | 2 | [1] |
Rabbi Trust Investments to Support the Deferred Compensation and SERP | 0 | [2] | 0 | [2] |
Total Assets | 12 | 2 | ||
Liabilities | ' | ' | ||
Liabilities | 0 | 0 | ||
Net Total Assets (Liability) | 12 | 2 | ||
Level 1 [Member] | Energy Contracts [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | 0 | [3] | 0 | [3] |
Level 1 [Member] | Energy Contracts Cash Flow Hedge [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | 0 | [3] | 0 | [3] |
Level 1 [Member] | Interest Rate Swap [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | 0 | [4] | 0 | [4] |
Level 1 [Member] | Energy Contracts [Member] | ' | ' | ||
Assets | ' | ' | ||
Derivative Assets | 0 | [3] | 0 | [3] |
Level 2 [Member] | ' | ' | ||
Assets | ' | ' | ||
Cash Equivalent | 0 | [1] | 0 | [1] |
Restricted Cash | 0 | [1] | 0 | [1] |
Rabbi Trust Investments to Support the Deferred Compensation and SERP | 25 | [2] | 22 | [2] |
Total Assets | 26 | 23 | ||
Liabilities | ' | ' | ||
Liabilities | -6 | -7 | ||
Net Total Assets (Liability) | 20 | 16 | ||
Level 2 [Member] | Energy Contracts [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | -2 | [3] | 0 | [3] |
Level 2 [Member] | Energy Contracts Cash Flow Hedge [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | 0 | [3] | 0 | [3] |
Level 2 [Member] | Interest Rate Swap [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | -4 | [4] | -7 | [4] |
Level 2 [Member] | Energy Contracts [Member] | ' | ' | ||
Assets | ' | ' | ||
Derivative Assets | 1 | [3] | 1 | [3] |
Level 3 [Member] | ' | ' | ||
Assets | ' | ' | ||
Cash Equivalent | 0 | [1] | 0 | [1] |
Restricted Cash | 0 | [1] | 0 | [1] |
Rabbi Trust Investments to Support the Deferred Compensation and SERP | 0 | [2] | 0 | [2] |
Derivative Assets | 0 | 1 | ||
Total Assets | 0 | 1 | ||
Liabilities | ' | ' | ||
Derivative Liability | -4 | -3 | ||
Liabilities | -4 | -3 | ||
Net Total Assets (Liability) | -4 | -2 | ||
Level 3 [Member] | Energy Contracts [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | -3 | [3] | -2 | [3] |
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | -1 | [3] | -1 | [3] |
Level 3 [Member] | Interest Rate Swap [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | 0 | [4] | 0 | [4] |
Level 3 [Member] | Energy Contracts [Member] | ' | ' | ||
Assets | ' | ' | ||
Derivative Assets | 0 | [3] | 1 | [3] |
Netting [Member] | ' | ' | ||
Assets | ' | ' | ||
Cash Equivalent | 0 | [1],[5] | 0 | [1],[5] |
Restricted Cash | 0 | [1],[5] | 0 | [1],[5] |
Rabbi Trust Investments to Support the Deferred Compensation and SERP | 0 | [2],[5] | 0 | [2],[5] |
Total Assets | -1 | [5] | -1 | [5] |
Liabilities | ' | ' | ||
Liabilities | 1 | [5] | 1 | [5] |
Net Total Assets (Liability) | 0 | [5] | 0 | [5] |
Netting [Member] | Energy Contracts [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | 1 | [3],[5] | 1 | [3],[5] |
Netting [Member] | Energy Contracts Cash Flow Hedge [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | 0 | [3],[5] | 0 | [3],[5] |
Netting [Member] | Interest Rate Swap [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | 0 | [4],[5] | 0 | [4],[5] |
Netting [Member] | Energy Contracts [Member] | ' | ' | ||
Assets | ' | ' | ||
Derivative Assets | -1 | [3],[5] | -1 | [3],[5] |
Net Fair Value [Member] | ' | ' | ||
Assets | ' | ' | ||
Cash Equivalent | 10 | [1] | 0 | [1] |
Restricted Cash | 2 | [1] | 2 | [1] |
Rabbi Trust Investments to Support the Deferred Compensation and SERP | 25 | [2] | 22 | [2] |
Total Assets | 37 | 25 | ||
Liabilities | ' | ' | ||
Liabilities | -9 | -9 | ||
Net Total Assets (Liability) | 28 | 16 | ||
Net Fair Value [Member] | Energy Contracts [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | -4 | [3] | -1 | [3] |
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | -1 | [3] | -1 | [3] |
Net Fair Value [Member] | Interest Rate Swap [Member] | ' | ' | ||
Liabilities | ' | ' | ||
Derivative Liability | -4 | [4] | -7 | [4] |
Net Fair Value [Member] | Energy Contracts [Member] | ' | ' | ||
Assets | ' | ' | ||
Derivative Assets | $0 | [3] | $1 | [3] |
[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 balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets. | |||
[2] | Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets. | |||
[3] | Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below. | |||
[4] | Interest Rate Swaps still held are valued based on the 6-month London Interbank Offered Rate (LIBOR). An interest rate swap valued based on the Securities Industry and Financial Markets Association Municipal swap index matured in September 2014. These interest rate swaps are included in Derivative Instruments on the balance sheets. | |||
[5] | All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets. |
FAIR_VALUE_MEASUREMENTS_AND_DE3
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) (Scenario, Forecast [Member], USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Sep. 30, 2015 |
Scenario, Forecast [Member] | ' |
Derivative [Line Items] | ' |
Estimated loss expected to be reclassified to earnings within the next twelve months | $2 |
FAIR_VALUE_MEASUREMENTS_AND_DE4
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' | ' | ' |
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities | ($6) | ($1) | ($4) | ($2) |
FAIR_VALUE_MEASUREMENTS_AND_DE5
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details) | Sep. 30, 2014 | Dec. 31, 2013 |
GWh | GWh | |
Power Contracts [Member] | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' |
Derivatives Volumes | 842 | 779 |
Gas Contracts [Member] | ' | ' |
Derivative Instruments, Gain (Loss) [Line Items] | ' | ' |
Derivatives Volumes | 20,595,000,000 | 9,615,000,000 |
FAIR_VALUE_MEASUREMENTS_AND_DE6
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Detail) (Level 3 [Member], USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ' | ' |
Derivative Assets | $0 | $1 |
Derivative Liability | -4 | -3 |
Market Approach Valuation Technique [Member] | Forward Contracts [Member] | ' | ' |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ' | ' |
Derivative Assets | 0 | 0 |
Derivative Liability | -3 | -3 |
Valuation Technique Option Model [Member] | Options Held [Member] | ' | ' |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ' | ' |
Derivative Assets | 0 | 1 |
Derivative Liability | ($1) | $0 |
Minimum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member] | ' | ' |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ' | ' |
Market price per MWh | 27.5 | 27 |
Minimum [Member] | Valuation Technique Option Model [Member] | Options Held [Member] | ' | ' |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ' | ' |
Market price per MMbtu | 3.67 | 3.88 |
Gas volatility | 24.88% | 25.05% |
Maximum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member] | ' | ' |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ' | ' |
Market price per MWh | 43.5 | 48.25 |
Maximum [Member] | Valuation Technique Option Model [Member] | Options Held [Member] | ' | ' |
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | ' | ' |
Market price per MMbtu | 4.24 | 4.32 |
Gas volatility | 40.62% | 35.07% |
FAIR_VALUE_MEASUREMENTS_AND_DE7
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Schedule of Reconciliation of Changes in Fair Value of Assets and Liabilities) (Detail) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items] | ' | ' | ' | ' |
Beginning balance | $0 | ($1) | ($2) | $0 |
Realized/Unrealized Gains/(Losses) Recorded to: | ' | ' | ' | ' |
Net Regulatory Assets/Liabilities - Derivative Instruments | -4 | -1 | -3 | -2 |
Settlements | 0 | 0 | 1 | 0 |
Ending balance | -4 | -2 | -4 | -2 |
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period | ($2) | $0 | ($2) | ($1) |
FAIR_VALUE_MEASUREMENTS_AND_DE8
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) (USD $) | Sep. 30, 2014 |
Derivative [Line Items] | ' |
FV of derivative instruments in net liability position with credit risk related features | $17,000,000 |
Letters of Credit Outstanding, Amount | 1,000,000 |
Collateral Already Posted, Aggregate Fair Value | 0 |
Collateral Held from Counterparties | 0 |
Additional collateral if credit-risk contingent features are triggered | $17,000,000 |
FAIR_VALUE_MEASUREMENTS_AND_DE9
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Detail) (USD $) | Sep. 30, 2014 | Dec. 31, 2013 |
Liabilities: | ' | ' |
Long-Term Debt | $1,372,369,000 | $1,223,070,000 |
Carrying Value [Member] | Level 2 [Member] | ' | ' |
Liabilities: | ' | ' |
Long-Term Debt | 1,372,000,000 | 1,223,000,000 |
Carrying Value [Member] | Level 3 [Member] | ' | ' |
Assets: | ' | ' |
Investment in Lease Equity | 36,000,000 | 36,000,000 |
Fair Value [Member] | Level 2 [Member] | ' | ' |
Liabilities: | ' | ' |
Long-Term Debt | 1,444,000,000 | 1,214,000,000 |
Fair Value [Member] | Level 3 [Member] | ' | ' |
Assets: | ' | ' |
Investment in Lease Equity | $26,000,000 | $25,000,000 |
INCOME_TAXES_Details
INCOME TAXES (Details) (USD $) | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||
Jun. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 | |
Income Tax Disclosure [Abstract] | ' | ' | ' | ' | ' |
Federal Income Tax Expense at Statutory Rate | ' | $22,000,000 | $36,000,000 | $49,000,000 | $48,000,000 |
State Income Tax Expense, Net of Federal Deduction | ' | 3,000,000 | 5,000,000 | 6,000,000 | 6,000,000 |
Federal/State Tax Credits | ' | -2,000,000 | -1,000,000 | -4,000,000 | -2,000,000 |
Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset | -11,000,000 | ' | ' | 0 | -11,000,000 |
Other | ' | 1,000,000 | -1,000,000 | 1,000,000 | 1,000,000 |
Income Tax Expense | ' | $23,576,000 | $38,828,000 | $51,656,000 | $41,737,000 |
RECLASSIFICATIONS_FROM_ACCUMUL2
RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT Reclassifications From Accumulated Other Comprehensive Income By Component) (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2014 | Sep. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2013 |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract] | ' | ' | ' | ' |
Interest Expense Long-Term Debt | $15,579 | $13,848 | $45,326 | $42,412 |
Interest Expense Capital Leases | 1,202 | 6,323 | 9,048 | 18,821 |
Purchased Energy | 49,902 | 42,477 | 125,423 | 89,815 |
Other Nonoperating Expense | -7,170 | -2,776 | -11,979 | -7,493 |
Income Tax Benefit | -23,576 | -38,828 | -51,656 | -41,737 |
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | -674 | -885 | -1,914 | -2,078 |
Other Comprehensive Income (Loss), Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service (Cost) Credit, Net of Tax | 25 | 68 | 74 | 205 |
Total Reclassification from Other Comprehensive Income for the Period | -699 | -953 | -1,988 | -2,283 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Realized Losses on Cash Flow Hedges, Net of Taxes | ' | ' | ' | ' |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract] | ' | ' | ' | ' |
Income Tax Benefit | 546 | 579 | 1,238 | 1,360 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Realized Losses on Cash Flow Hedges, Net of Taxes | Interest Rate Swaps - Debt | ' | ' | ' | ' |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract] | ' | ' | ' | ' |
Interest Expense Long-Term Debt | -291 | -296 | -882 | -871 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Realized Losses on Cash Flow Hedges, Net of Taxes | Interest Rate Swaps - Capital Leases | ' | ' | ' | ' |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract] | ' | ' | ' | ' |
Interest Expense Capital Leases | -451 | -612 | -1,649 | -1,820 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Realized Losses on Cash Flow Hedges, Net of Taxes | Commodity Contracts | ' | ' | ' | ' |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract] | ' | ' | ' | ' |
Purchased Energy | -478 | -556 | -621 | -747 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Amortization, Net of Taxes | ' | ' | ' | ' |
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract] | ' | ' | ' | ' |
Other Nonoperating Expense | -40 | -110 | -119 | -332 |
Income Tax Benefit | $15 | $42 | $45 | $127 |