Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended |
Mar. 31, 2015 | |
Document And Entity Information [Abstract] | |
Document Type | S-4 |
Amendment Flag | FALSE |
Document Period End Date | 31-Mar-15 |
Entity Registrant Name | TUCSON ELECTRIC POWER COMPANY |
Entity Central Index Key | 100122 |
Entity Filer Category | Non-accelerated Filer |
CONDENSED_CONSOLIDATED_BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | |||
Utility Plant | |||
Plant in Service | $5,225,923 | $5,175,148 | $4,467,667 |
Utility Plant Under Capital Leases | 436,199 | 667,157 | 637,957 |
Construction Work in Progress | 173,889 | 109,070 | 180,485 |
Total Utility Plant | 5,836,011 | 5,951,375 | 5,286,109 |
Less Accumulated Depreciation and Amortization | -2,091,266 | -2,052,216 | -1,826,977 |
Less Accumulated Amortization of Capital Lease Assets | -286,693 | -473,969 | -514,677 |
Total Utility Plant-Net | 3,458,052 | 3,425,190 | 2,944,455 |
Investments and Other Property | |||
Investments in Lease Equity | 0 | 36,194 | |
Other | 37,599 | 33,488 | |
Investments and Other Property | 38,428 | 37,599 | 69,682 |
Current Assets | |||
Cash and Cash Equivalents | 65,348 | 74,170 | 25,335 |
Accounts Receivable-Customer | 72,702 | 80,713 | |
Accounts Receivable-Other | 15,498 | 12,808 | |
Unbilled Accounts Receivable | 32,069 | 36,804 | 34,369 |
Allowance for Doubtful Accounts | -4,776 | -4,885 | -4,825 |
Allowance for Doubtful Accounts-Other | -5,521 | 0 | |
Accounts Receivable-Due from Affiliates | 4,617 | 5,382 | 6,064 |
Materials and Supplies | 89,043 | 86,750 | 75,200 |
Deferred Income Taxes-Current | 98,633 | 102,006 | 70,722 |
Fuel Inventory | 33,758 | 36,368 | 44,027 |
Regulatory Assets-Current | 79,380 | 69,383 | 42,555 |
Derivative Instruments | 248 | 1,633 | 2,137 |
Other | 25,557 | 22,848 | 12,923 |
Total Current Assets | 506,556 | 523,980 | 388,718 |
Regulatory and Other Assets | |||
Regulatory Assets-Noncurrent | 238,018 | 223,192 | 141,030 |
Derivative Instruments | 520 | 300 | 167 |
Other Assets | 21,340 | 22,161 | 19,233 |
Total Regulatory and Other Assets | 259,878 | 245,653 | 160,430 |
Total Assets | 4,262,915 | 4,232,422 | 3,563,285 |
Capitalization | |||
Common Stock Equity | 1,225,282 | 1,215,779 | 925,923 |
Capital Lease Obligations | 59,957 | 69,438 | 131,370 |
Long-Term Debt | 1,541,486 | 1,372,414 | 1,223,070 |
Total Capitalization | 2,826,726 | 2,657,631 | 2,280,363 |
Current Liabilities | |||
Current Obligations Under Capital Leases | 131,428 | 173,822 | 186,056 |
Borrowings Under Revolving Credit Facilities | 0 | 85,000 | 0 |
Accounts Payable-Trade | 93,682 | 110,480 | 88,556 |
Accounts Payable-Due to Affiliates | 4,200 | 2,933 | 9,153 |
Accrued Taxes Other than Income Taxes | 47,482 | 36,110 | 34,485 |
Accrued Employee Expenses | 20,766 | 15,679 | 24,454 |
Regulatory Liabilities-Current | 33,308 | 38,847 | 23,701 |
Accrued Interest | 16,190 | 21,021 | 22,785 |
Customer Deposits | 20,047 | 20,339 | 21,354 |
Derivative Instruments | 22,016 | 18,874 | 5,531 |
Other | 11,168 | 9,673 | 9,244 |
Total Current Liabilities | 400,287 | 532,778 | 425,319 |
Deferred Credits and Other Liabilities | |||
Deferred Income Taxes-Noncurrent | 492,662 | 491,546 | 428,103 |
Regulatory Liabilities-Noncurrent | 313,062 | 321,186 | 263,270 |
Pension and Other Postretirement Benefits | 138,585 | 138,319 | 84,936 |
Derivative Instruments | 7,476 | 6,288 | 5,161 |
Other | 84,116 | 84,674 | 76,133 |
Total Deferred Credits and Other Liabilities | 1,035,902 | 1,042,013 | 857,603 |
Commitments, Contingencies & Environmental Matters (Note 5) | |||
Total Capitalization and Other Liabilities | 4,262,915 | 4,232,422 | 3,563,285 |
Scenario, Previously Reported [Member] | |||
Current Assets | |||
Accounts Receivable-Customer | $93,521 | $80,211 |
CONDENSED_CONSOLIDATED_STATEME
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $) | 3 Months Ended | 12 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Operating Revenues | |||||
Electric Retail Sales | $201,622 | $186,015 | $970,145 | $934,357 | $915,879 |
Electric Wholesale Sales | 41,462 | 42,084 | 158,323 | 132,500 | 111,194 |
Other Revenues | 30,308 | 27,414 | 141,433 | 129,833 | 134,587 |
Total Operating Revenues | 273,392 | 255,513 | 1,269,901 | 1,196,690 | 1,161,660 |
Operating Expenses | |||||
Fuel | 70,569 | 67,630 | 297,537 | 325,903 | 318,901 |
Purchased Power | 30,522 | 22,615 | 152,922 | 112,452 | 80,137 |
Transmission and Other PPFAC Recoverable Costs | 4,707 | 3,909 | 18,179 | 12,233 | 5,722 |
Increase (Decrease) to Reflect PPFAC Recovery Treatment | 3,249 | -1,730 | -11,194 | -12,458 | 31,113 |
Total Fuel and Purchased Energy | 109,047 | 92,424 | 457,444 | 438,130 | 435,873 |
Operations and Maintenance | 82,645 | 81,345 | 378,877 | 335,321 | 334,553 |
Depreciation | 34,733 | 30,811 | 126,520 | 118,076 | 110,931 |
Amortization | 5,562 | 7,099 | 28,567 | 31,294 | 39,493 |
Taxes Other Than Income Taxes | 13,212 | 11,835 | 47,805 | 43,498 | 40,323 |
Total Operating Expenses | 245,199 | 223,514 | 1,039,213 | 966,319 | 961,173 |
Operating Income | 28,193 | 31,999 | 230,688 | 230,371 | 200,487 |
Other Income (Deductions) | |||||
Interest Income | 29 | 9 | 208 | 120 | 136 |
Other Income | 622 | 1,912 | 8,598 | 5,770 | 3,953 |
Other Expense | -462 | -2,115 | -12,735 | -10,715 | -13,574 |
Appreciation (Depreciation) in Fair Value of Investments | 780 | 255 | 1,371 | 2,833 | 1,892 |
Total Other Income (Deductions) | 969 | 61 | -2,558 | -1,992 | -7,593 |
Interest Expense | |||||
Long-Term Debt | 14,410 | 14,240 | 60,577 | 56,378 | 55,038 |
Capital Leases | 1,004 | 3,921 | 10,249 | 25,140 | 33,613 |
Other Interest Expense | 434 | 313 | 810 | 87 | 1,446 |
Interest Capitalized | -454 | -924 | -3,755 | -2,554 | -1,782 |
Total Interest Expense | 15,394 | 17,550 | 67,881 | 79,051 | 88,315 |
Income Before Income Taxes | 13,768 | 14,510 | 160,249 | 149,328 | 104,579 |
Income Tax Expense | 4,339 | 5,338 | 57,911 | 47,986 | 39,109 |
Net Income | $9,429 | $9,172 | $102,338 | $101,342 | $65,470 |
CONDENSED_CONSOLIDATED_STATEME1
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) | 3 Months Ended | 12 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Statement of Comprehensive Income [Abstract] | |||||
Net Income | $9,429 | $9,172 | $102,338 | $101,342 | $65,470 |
Other Comprehensive Income (Loss) | |||||
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit | 14 | 481 | 1,675 | 2,738 | 1,354 |
Supplemental Executive Retirement Plan (SERP) Net Loss and Prior Service Cost Amortization, net of income tax (expense) benefit | 60 | 24 | -1,725 | 916 | -840 |
Total Other Comprehensive Income (Loss), Net of Taxes | 74 | 505 | -50 | 3,654 | 514 |
Total Comprehensive Income | $9,503 | $9,677 | $102,288 | $104,996 | $65,984 |
CONDENSED_CONSOLIDATED_STATEME2
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) | 3 Months Ended | 12 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Statement of Comprehensive Income [Abstract] | |||||
Income Tax (Expense) Benefit, Net Changes in Fair Value of Cash Flow Hedges | ($12) | ($346) | ($1,140) | ($1,793) | ($887) |
Income Tax (Expense) Benefit, SERP Amortization | ($37) | ($15) | $1,068 | ($572) | $608 |
CONDENSED_CONSOLIDATED_STATEME3
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 3 Months Ended | 12 Months Ended | |||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Statement of Cash Flows [Abstract] | |||||
Net Income | $9,429 | $9,172 | $102,338 | $101,342 | $65,470 |
Cash Flows from Operating Activities | |||||
Depreciation | 34,733 | 30,811 | 126,520 | 118,076 | 110,931 |
Amortization Expense | 5,562 | 7,099 | 28,567 | 31,294 | 39,493 |
Amortization of Deferred Debt-Related Costs included in Interest Expense | 716 | 635 | 2,626 | 2,452 | 2,227 |
Provision for Springerville Unit 1-Third-Party Owners Unrealized Revenue | 5,521 | 0 | |||
Use of Renewable Energy Credits for Compliance | 7,210 | 4,844 | 17,818 | 15,990 | 5,071 |
Deferred Income Taxes | 4,339 | 5,337 | 62,609 | 59,199 | 45,232 |
Pension and Retiree Expense | 4,647 | 3,412 | 13,648 | 19,878 | 19,289 |
Pension and Retiree Funding | -2,624 | -1,657 | -14,388 | -27,636 | -25,899 |
Share-Based Compensation Expense | 656 | 792 | 5,010 | 2,709 | 2,029 |
Allowance for Equity Funds Used During Construction | -343 | -1,721 | -6,677 | -4,526 | -2,840 |
LFCR Revenue | -3,000 | -5,000 | -11,327 | -2,171 | 0 |
LFCR and DSM Revenues | -5,461 | -6,226 | |||
Increase (Decrease) to Reflect PPFAC Recovery | 3,249 | -1,730 | -11,194 | -12,458 | 31,113 |
Fortis Acquisition Direct Customer Benefit | 18,870 | 0 | 0 | ||
PPFAC Reduction-2013 TEP Rate Order | 0 | 3,000 | 0 | ||
Changes in Assets and Liabilities which Provided (Used) Cash Exclusive of Changes Shown Separately[Abstract] | |||||
Accounts Receivable | 9,947 | 16,274 | -14,599 | -6,041 | -871 |
Materials and Fuel Inventory | -4,239 | -3,182 | 666 | 16,145 | -38,384 |
Accounts Payable | -12,046 | -3,425 | 10,712 | 334 | 1,115 |
Interest Accrued | -2,559 | -3,260 | -377 | 4,859 | 8,055 |
Taxes Other Than Income Taxes | 11,372 | 9,948 | 1,625 | 1,425 | 905 |
Current Regulatory Liabilities | 8,388 | 3,331 | -3,040 | ||
Other | -2,621 | -1,809 | -27,172 | 18,989 | 8,023 |
Net Cash Flows - Operating Activities | 67,488 | 65,314 | 313,663 | 346,191 | 267,919 |
Cash Flows from Investing Activities | |||||
Capital Expenditures | -99,291 | -72,570 | -323,524 | -252,848 | -252,782 |
Purchase of Gila River Unit 3 | -163,938 | 0 | 0 | ||
Purchase of Springerville Unit 1 Lease Assets | -45,753 | 0 | -19,608 | 0 | 0 |
Purchase of Intangibles-Renewable Energy Credits | -6,325 | -5,431 | -28,334 | -23,280 | -8,889 |
Return of Investments in Springerville Lease Debt | 0 | 9,104 | 19,278 | ||
CIAC | 959 | 5,746 | 15,903 | 3,959 | 9,982 |
Other, net | 0 | 1,664 | 1,863 | 3,403 | 4,530 |
Net Cash Flows-Investing Activities | -150,410 | -70,591 | -517,638 | -259,662 | -227,881 |
Cash Flows from Financing Activities | |||||
Proceeds from Borrowings Under Revolving Credit Facilities | 15,000 | 105,000 | 275,000 | 78,000 | 189,000 |
Repayments of Borrowings Under Revolving Credit Facilities | -100,000 | -105,000 | -190,000 | -78,000 | -199,000 |
Proceeds from Borrowings Under Term Loan | 130,000 | 0 | |||
Repayments of Borrowings Under Term Loan | -130,000 | 0 | |||
Proceeds from Issuance of Long-Term Debt | 299,019 | 149,168 | 149,168 | 0 | 149,513 |
Payments of Capital Lease Obligations | -8,394 | -79,737 | -165,145 | -99,621 | -89,452 |
Dividends Paid to UNS Energy | -40,000 | -40,000 | -30,000 | ||
Repayments of Long-Term Debt | -130,000 | 0 | 0 | 0 | -6,535 |
Payment of Debt Issue/Retirement Costs | -2,372 | -1,471 | -1,856 | -1,865 | -3,547 |
Equity Investment from UNS Energy | 225,000 | 0 | 0 | ||
Other, net | 847 | 3 | 643 | 549 | 2,008 |
Net Cash Flows-Financing Activities | 74,100 | 67,963 | 252,810 | -140,937 | 11,987 |
Net Increase (Decrease) in Cash and Cash Equivalents | -8,822 | 62,686 | 48,835 | -54,408 | 52,025 |
Cash and Cash Equivalents, Beginning of Year | 74,170 | 25,335 | 25,335 | 79,743 | 27,718 |
Cash and Cash Equivalents, End of Period | $65,348 | $88,021 | $74,170 | $25,335 | $79,743 |
CONDENSED_CONSOLIDATED_STATEME4
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY (USD $) | Total | Common Stock [Member] | Common Stock-No Par Value | Capital Stock Expense | Accumulated Earnings | Accumulated Other Comprehensive Loss |
In Thousands, except Share data, unless otherwise specified | USD ($) | USD ($) | USD ($) | USD ($) | USD ($) | |
Balances at Dec. 31, 2011 | $824,943 | $888,971 | ($6,357) | ($47,627) | ($10,044) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Net Income | 65,470 | 65,470 | ||||
Other Comprehensive Income, net of tax | 514 | 514 | ||||
Dividends Declared | -30,000 | -30,000 | ||||
Balances at Dec. 31, 2012 | 860,927 | 888,971 | -6,357 | -12,157 | -9,530 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Net Income | 101,342 | 101,342 | ||||
Other Comprehensive Income, net of tax | 3,654 | 3,654 | ||||
Dividends Declared | -40,000 | -40,000 | ||||
Balances at Dec. 31, 2013 | 925,923 | 888,971 | -6,357 | 49,185 | -5,876 | |
Common Shares at Dec. 31, 2013 | 32,139,434 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Net Income | 102,338 | 102,338 | ||||
Other Comprehensive Income, net of tax | -50 | -50 | ||||
Dividends Declared | -40,000 | -40,000 | ||||
Contribution from Parent | 225,000 | 225,000 | ||||
Other | 2,568 | 2,568 | ||||
Balances at Dec. 31, 2014 | 1,215,779 | 1,116,539 | -6,357 | 111,523 | -5,926 | |
Common Shares at Dec. 31, 2014 | 32,139,434 | 32,139,000 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Net Income | 9,429 | 9,429 | ||||
Other Comprehensive Income, net of tax | 74 | 74 | ||||
Balances at Mar. 31, 2015 | $1,225,282 | $1,116,539 | ($6,357) | $120,952 | ($5,852) | |
Common Shares at Mar. 31, 2015 | 32,139,000 |
CONSOLIDATED_STATEMENTS_OF_CAP
CONSOLIDATED STATEMENTS OF CAPITALIZATION (USD $) | 12 Months Ended | |
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Shares Authorized | 75,000,000 | 75,000,000 |
Shares Outstanding | 32,139,434 | 32,139,434 |
Total Common Stock Equity | $1,215,779 | $925,923 |
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
No Par Value, 1,000,000 Shares Authorized, None Outstanding | 0 | 0 |
Capital Lease Obligations [Abstract] | ||
Total Capital Lease Obligations | 243,260 | 317,426 |
Less Current Maturities | 173,822 | 186,056 |
Total Long-Term Capital Lease Obligations | 69,438 | 131,370 |
Long-term Debt, Unclassified [Abstract] | ||
Long-term Debt | 1,372,414 | 1,223,070 |
Total Capitalization | 2,657,631 | 2,280,363 |
Springerville Unit 1 | ||
Capital Lease Obligations [Abstract] | ||
Total Capital Lease Obligations | 42,925 | 192,871 |
Springerville Coal Handling Facilities | ||
Capital Lease Obligations [Abstract] | ||
Total Capital Lease Obligations | 117,573 | 27,878 |
Springerville Common Facilities | ||
Capital Lease Obligations [Abstract] | ||
Total Capital Lease Obligations | 82,762 | 96,677 |
Variable Rate Bonds | ||
Long-term Debt, Unclassified [Abstract] | ||
Long-term Debt | 214,830 | 214,802 |
Debt Instrument, Maturity Date Range, Start | 1-Oct-22 | |
Debt Instrument, Maturity Date Range, End | 1-Apr-32 | |
Debt Instrument Interest Rate | Variable | |
Fixed Rate Bonds | ||
Long-term Debt, Unclassified [Abstract] | ||
Long-term Debt | 1,157,584 | 1,008,268 |
Debt Instrument, Maturity Date Range, Start | 1-Oct-20 | |
Debt Instrument, Maturity Date Range, End | 15-Mar-44 | |
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum | 3.85% | |
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum | 5.75% | |
Common Stock-No Par Value | ||
Total Common Stock Equity | 1,116,539 | 888,971 |
Capital Stock Expense | ||
Total Common Stock Equity | -6,357 | -6,357 |
Accumulated Earnings | ||
Total Common Stock Equity | 111,523 | 49,185 |
Accumulated Other Comprehensive Loss | ||
Total Common Stock Equity | ($5,926) | ($5,876) |
NATURE_OF_OPERATIONS_AND_FINAN
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION | 3 Months Ended |
Mar. 31, 2015 | |
Accounting Policies [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 417,000 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. 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. | |
BASIS OF PRESENTATION | |
We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP), including specific accounting guidance for regulated operations and the Securities and Exchange Commission’s (SEC) interim reporting requirements. See Note 2. The condensed consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stations and transmission facilities with both affiliated and non-affiliated entities. TEP’s proportionate share of jointly owned facilities is recorded as Utility Plant on the condensed consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the condensed consolidated statements of income. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2014 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. | |
In 2014, following the acquisition of UNS Energy by Fortis, TEP 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. | |
RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS | |
In 2015, we adopted accounting guidance that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. The adoption of this guidance did not have any impact on our disclosures, financial condition, results of operations, or cash flows. |
REGULATORY_MATTERS
REGULATORY MATTERS | 3 Months Ended | 12 Months Ended | ||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||
Regulated Operations [Abstract] | ||||||||||
REGULATORY MATTERS | REGULATORY MATTERS | REGULATORY MATTERS | ||||||||
The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (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 | 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. | |||||||||
Purchased Power and Fuel Adjustment Clause | ||||||||||
The ACC adjusts TEP’s Purchased Power and Fuel Adjustment Clause (PPFAC) rate annually each April 1 for the subsequent 12-month period. The ACC approved rates of 0.50 cents per Kilowatt-hours (kWh) for the three months ended March 31, 2015 and 0.14 cents per kWh for the three months ended March 31, 2014. In March 2015, the ACC approved a PPFAC rate for TEP of 0.68 cents per kWh for the period April 2015 through March 2016. | 2013 TEP RATE ORDER | |||||||||
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 March 31, 2015, TEP has received insurance settlement proceeds of $8 million. 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 incremental fuel costs, not reimbursed by insurance, through its PPFAC. | ||||||||||
The provisions of the 2013 TEP Rate Order, which were effective July 1, 2013, include, but are not limited to: | ||||||||||
Environmental Compliance Adjustor | ||||||||||
The 2013 TEP Rate Order provided an Environmental Compliance Adjustor (ECA) to recover the return on and of qualified investments, including related operating expenses, 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 recognized ECA revenues of less than $0.5 million in the first three months of 2015. | ||||||||||
Energy Efficiency Standards | • | An annual increase in Base Rates of approximately $76 million. | ||||||||
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 an annual performance incentive. In the first three months of 2015, TEP recorded an annual DSM performance incentive of $3 million related to savings realized in 2014 that is included in the Electric Retail Sales line item in the accompanying condensed consolidated statements of income. | ||||||||||
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. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of the company’s total retail revenues. | • | A revision in depreciation rates from an average rate of 3.32% to 3.0% for generation and distribution plant regulated by the ACC, primarily due to revised estimates of asset removal costs, which has the effect of reducing depreciation expense by approximately $11 million annually. | ||||||||
TEP recorded a regulatory asset and recognized LFCR revenues of $3 million and $5 million in the first three months of 2015 and 2014, respectively. LFCR revenues are included in the Electric Retail Sales in the accompanying condensed consolidated statements of income. | ||||||||||
The ACC approved recovery of $5 million through the LFCR recovery mechanism effective August 2014 for the subsequent 12-month period. | ||||||||||
REGULATORY ASSETS | • | A LFCR mechanism that allows TEP to recover certain non-fuel costs that would otherwise go unrecovered due to reduced retail kWh sales attributed to EE programs and DG. The LFCR rate adjusts annually and is subject to ACC review and a year-over-year cap of 1% of TEP’s total retail revenues. | ||||||||
TEP’s total regulatory assets, including current and noncurrent assets, increased $25 million at March 31, 2015 from December 31, 2014, primarily due to the reclassification of unamortized leasehold improvement costs upon expiration of the Springerville Unit 1 capital lease in January 2015 that relate to third-party ownership interests. These leasehold improvements, previously recorded in Plant in Service, represent investments TEP made through the end of the lease term to ensure that the Springerville facilities continued providing safe, reliable service to TEP’s customers. In its 2013 Rate Case, TEP requested and received ACC authorization to use a 10-year amortization period for leasehold improvements at Springerville Unit 1. TEP owns a 49.5% undivided interest in Springerville Unit 1. | ||||||||||
• | An Environmental Compliance Adjustor (ECA) mechanism that allows TEP to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. The ECA adjusts annually to recover environmental compliance costs and is subject to ACC approval and a cap of 0.025 cents per kWh, which approximates 0.25% of TEP’s total retail revenues. | |||||||||
COST RECOVERY MECHANISMS | ||||||||||
Purchased Power and Fuel Adjustment Clause | ||||||||||
The PPFAC rate is adjusted annually each April 1st (unless otherwise approved by the ACC) and goes into effect for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: 1) a forward component, under which TEP recovers or refunds differences between a) forecasted fuel, transmission, and purchased power costs for the upcoming calendar year and b) those embedded in the fuel rate and the current PPFAC rates; and 2) a true-up component, which reconciles differences between actual fuel, transmission, and purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 12-month period. | ||||||||||
In April 2014, the ACC approved a 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 0.77 cents per kWh for the period of January 2013 through June 2013 and 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 December 31, 2014, TEP has received insurance settlement proceeds of $8 million. 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 for the ECA to recover costs associated with 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 recognized ECA revenues of less than $1 million in 2014. | ||||||||||
Renewable Energy Standards | ||||||||||
TEP is required to expand its use of renewable energy in order to meet the ACC’s Renewable Energy Standards (RES). TEP is authorized to recover costs associated with meeting the RES through a customer surcharge. These costs include purchases of RECs through Power Purchase Agreements (PPAs) and Performance Based Incentives (PBIs), as well as costs associated with utility-scale ownership of solar assets until the projects can be incorporated in Base Rates. | ||||||||||
In December 2014, the ACC approved TEP’s 2015 RES plan that included a spending budget of $40 million with $33 million to be recovered through the RES surcharge. TEP earned returns on solar investments of less than $1 million in 2014 and $2 million in 2013. | ||||||||||
Energy Efficiency Standards | ||||||||||
TEP is required to implement cost-effective DSM programs to comply with the ACC’s 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. For the year ended December 31, 2014, TEP recorded a DSM performance incentive of $2 million that is included in Electric Retail Revenue in the TEP income statement. | ||||||||||
Lost Fixed Cost Recovery Mechanism | ||||||||||
The 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 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. | ||||||||||
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. | ||||||||||
TEP recorded, in Electric Retail Sales, LFCR revenues of $11 million for the year ended December 31, 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 following table summarizes regulatory assets and liabilities: | ||||||||||
December 31, 2014 | December 31, 2013 | |||||||||
Millions of Dollars | ||||||||||
Regulatory Assets-Current | ||||||||||
Property Tax Deferrals(1) | $ | 21 | $ | 20 | ||||||
PPFAC(2) | 19 | 4 | ||||||||
Derivative Instruments (Note 10) | 15 | 1 | ||||||||
LFCR and DSM(2) | 8 | 3 | ||||||||
San Juan Mine Fire Cost Deferral(2) | 2 | 10 | ||||||||
Other Current Regulatory Assets(3) | 4 | 5 | ||||||||
Total Regulatory Assets—Current | 69 | 43 | ||||||||
Regulatory Assets—Noncurrent | ||||||||||
Pension and Other Retiree Benefits (Note 8) | 126 | 75 | ||||||||
Income Taxes Recoverable Through Future Rates(4) | 31 | 22 | ||||||||
PPFAC - Final Mine Reclamation and Retiree Health Care Costs(5) | 29 | 25 | ||||||||
Springerville Lease Purchase Commitment Deferrals(6) | 16 | 2 | ||||||||
Unamortized Loss on Reacquired Debt(7) | 6 | 7 | ||||||||
LFCR(2) | $ | 4 | $ | — | ||||||
Tucson to Nogales Transmission Line(8) | 4 | 5 | ||||||||
Other Regulatory Assets(3) | 7 | 5 | ||||||||
Total Regulatory Assets—Noncurrent | 223 | 141 | ||||||||
Regulatory Liabilities—Current | ||||||||||
RES(2) | (28 | ) | (22 | ) | ||||||
DSM(2) | (6 | ) | — | |||||||
Fortis Merger Customer Credits(9) | (5 | ) | — | |||||||
Other Current Regulatory Liabilities | — | (2 | ) | |||||||
Total Regulatory Liabilities—Current | (39 | ) | (24 | ) | ||||||
Regulatory Liabilities—Noncurrent | ||||||||||
Net Cost of Removal for Interim Retirements(10) | (265 | ) | (254 | ) | ||||||
Deferred Investment Tax Credits(11) | (25 | ) | (4 | ) | ||||||
Income Taxes Payable through Future Rates(4) | (20 | ) | (5 | ) | ||||||
Fortis Merger Customer Credits(9) | (11 | ) | — | |||||||
Total Regulatory Liabilities—Noncurrent | (321 | ) | (263 | ) | ||||||
Total Net Regulatory Assets (Liabilities) | $ | (68 | ) | $ | (103 | ) | ||||
Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. With the exception of interest earned on under-recovered PPFAC costs, we do not earn a return on regulatory assets. Regulatory liabilities represent items that we either expect to pay to customers through billing reductions in future periods or plan to use for the purpose for which they were collected from customers. | ||||||||||
-1 | Property Taxes are recovered over approximately a six months period as costs are paid, rather than as costs are accrued. | |||||||||
-2 | See Cost Recovery Mechanisms discussed above. | |||||||||
-3 | Other regulatory assets include self-insured medical costs and short-term disability costs recovered on a pay-as-you-go or cash basis; San Juan Coal Contract Amendment costs (recovery through 2017); rate case costs (recovery over three years); and environmental compliance costs (recovery over one year). | |||||||||
-4 | Income Taxes Recoverable through Future Revenues are amortized over the life of the assets. See Note 1 of Notes to Consolidated Financial Statements. | |||||||||
-5 | Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years. | |||||||||
-6 | TEP deferred the increase in lease interest expense relating to the purchase commitments for Springerville Unit 1 and the Springerville Coal Handling Facilities to a regulatory asset because TEP believes the full purchase price is recoverable in rate base. See Note 5 of Notes to Consolidated Financial Statements. | |||||||||
-7 | In accordance with FERC guidelines, when TEP refinances its long-term debt, TEP defers and amortizes losses on reacquired debt over the life of the debt agreement. | |||||||||
-8 | TEP will request recovery from FERC for the costs incurred to develop a high-voltage transmission line from Tucson to Nogales; the project is not going forward. See Note 6 of Notes to Consolidated Financial Statements | |||||||||
-9 | Fortis Merger Customer Credits represent credits to be applied to customers’ bills according to the Merger Agreement. These credits will be applied to customer bills each year, October through March for a period of five years. See Note 1 of Notes to Consolidated Financial Statements. | |||||||||
-10 | Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future. | |||||||||
-11 | The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset. | |||||||||
IMPACTS OF REGULATORY ACCOUNTING | ||||||||||
If we determine that we no longer meet the criteria for continued application of regulatory accounting, we would be required to write off our regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on our financial statements. |
RELATED_PARTY_TRANSACTIONS
RELATED PARTY TRANSACTIONS | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||||||||||||||
Related Party Transactions [Abstract] | ||||||||||||||||||||||
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS | ||||||||||||||||||||
TEP engages in various transactions with Fortis, Inc., UNS Energy and its affiliated subsidiaries including Unisource Energy Services, Inc., 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. | TEP engages in various transactions with UNS Energy and its affiliated subsidiaries including Unisource Energy Services, 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 jointly own a generating station unit. See Note 7 of Notes to Consolidated Financial Statements. | |||||||||||||||||||||
At March 31, 2015 and December 31, 2014, our balance sheets include the following intercompany balances: | The following table summarizes related party transactions: | |||||||||||||||||||||
Balances at | Years Ended December 31, | |||||||||||||||||||||
March 31, 2015 | December 31, 2014 | 2014 | 2013 | 2012 | ||||||||||||||||||
Millions of Dollars | Millions of Dollars | |||||||||||||||||||||
Receivables from Related Parties | Wholesale Sales - TEP to UNS Electric(1) | $ | 4 | $ | 1 | $ | 2 | |||||||||||||||
UNS Electric | $ | 4 | $ | 4 | Wholesale Sales - UNS Electric to TEP(1) | 4 | 2 | 1 | ||||||||||||||
UNS Gas | 1 | 1 | Control Area Services - TEP to UNS Electric(2) | 3 | 4 | 3 | ||||||||||||||||
Common Costs - TEP to UNS Energy Affiliates(3) | 13 | 12 | 12 | |||||||||||||||||||
Total Due from Related Parties | $ | 5 | $ | 5 | Supplemental Workforce - UNS Energy Affiliate to TEP(4) | 16 | 16 | 17 | ||||||||||||||
Corporate Services - UNS Energy to TEP(5) | 14 | 5 | 2 | |||||||||||||||||||
Payables to Related Parties | Corporate Services - UNS Energy Affiliates to TEP(6) | 1 | 1 | 1 | ||||||||||||||||||
SES | $ | 3 | $ | 2 | ||||||||||||||||||
UNS Energy | 1 | — | ||||||||||||||||||||
UNS Electric | — | 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. | |||||||||||||||||||||
Total Due to Related Parties | $ | 4 | $ | 3 | -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 | Corporate costs at UNS Energy, such as merger costs and legal and audit fees, are allocated to its subsidiaries using the Massachusetts’ Formula, an industry accepted method of allocating common costs to affiliated entities. TEP’s allocation is approximately 81% of UNS Energy’s allocated costs. | |||||||||||||||||||||
The following table summarizes related party transactions: | -6 | All Corporate Services (e.g., 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. | ||||||||||||||||||||
At December 31, 2014 and December 31, 2013, our Balance Sheets include the following intercompany balances: | ||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
2015 | 2014 | |||||||||||||||||||||
Millions of Dollars | December 31, 2014 | December 31, 2013 | ||||||||||||||||||||
Wholesale Sales—TEP to UNS Electric (1) | $ | 2 | $ | — | Millions of Dollars | |||||||||||||||||
Control Area Services—TEP to UNS Electric (2) | — | 1 | Receivables from Related Parties | |||||||||||||||||||
Common Costs—TEP to UNS Energy Affiliates (3) | 3 | 3 | UNS Electric | $ | 4 | $ | 3 | |||||||||||||||
Supplemental Workforce—SES to TEP (4) | 4 | 4 | UNS Gas | 1 | 2 | |||||||||||||||||
Corporate Services—UNS Energy to TEP (5) | 1 | 1 | UNS Energy | — | 1 | |||||||||||||||||
Total Due from Related Parties | $ | 5 | $ | 6 | ||||||||||||||||||
(1) | TEP sells power to UNS Electric at prevailing market prices. | |||||||||||||||||||||
(2) | TEP charges UNS Electric for control area services under a FERC-accepted Control Area Services Agreement. | Payables to Related Parties | ||||||||||||||||||||
(3) | Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable. | SES | $ | 2 | $ | 2 | ||||||||||||||||
(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. | UNS Electric | 1 | — | ||||||||||||||||||
(5) | Corporate costs at UNS Energy, such as Fortis management fees, legal fees, and audit fees, are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP’s allocation is approximately 81% of UNS Energy’s allocated costs. For the three months ended March 31, 2015 these costs included approximately $1 million in Fortis management fees and for the three months ended March 31, 2014 these costs included approximately $1 million in merger related costs. | UNS Energy | — | 7 | ||||||||||||||||||
Total Due to Related Parties | $ | 3 | $ | 9 | ||||||||||||||||||
Share-Based Compensation Expense | ||||||||||||||||||||||
In January 2015, UNS Energy established a new share-based compensation plan, referred to as the 2015 Share Unit Plan (the Plan), to promote greater alignment of interests between the senior management of UNS Energy and its subsidiaries and the shareholders of Fortis. TEP recognized less than $1 million of share-based compensation expense under the Plan for the three months ended March 31, 2015. For the three months ended March 31, 2014, TEP recognized less than $1 million of expense under UNS Energy’s prior share-based compensation plan. |
DEBT_AND_CAPITAL_LEASE_OBLIGAT
DEBT AND CAPITAL LEASE OBLIGATIONS | 3 Months Ended | 12 Months Ended | ||||||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||||||
Debt Disclosure [Abstract] | ||||||||||||||
DEBT AND CAPITAL LEASE OBLIGATIONS | DEBT AND CAPITAL LEASE OBLIGATIONS | DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS | ||||||||||||
We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2014 Annual Report on Form 10-K. | Long-term debt matures more than one year from the date of the financial statements. We summarize TEP’s long-term debt in the statements of capitalization. | |||||||||||||
DEBT ISSUANCES AND REDEMPTIONS | ||||||||||||||
CAPITAL LEASE OBLIGATIONS | Fixed Rate Notes | |||||||||||||
Springerville Unit 1 Capital Lease Purchase | In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. TEP may redeem the notes prior to September 2043, with a make-whole premium plus accrued interest. After September 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 2010 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. | |||||||||||||
In January 2015, TEP purchased leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million, the appraised value. With the completion of the lease option purchase, TEP owns 49.5% of Springerville Unit 1, or 192 MW of capacity. Furthermore, TEP is obligated to operate the unit for the Third-Party Owners under an existing facility support agreement. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses. See Note 5. | In September 2012, TEP issued $150 million of 3.85% unsecured notes due March 2023. TEP may call the debt prior to December 2022, with a make-whole premium plus accrued interest. After December 2022, TEP may call the debt at par plus accrued interest. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding. TEP used the net proceeds to repay approximately $72 million outstanding on the 2010 Revolving Credit Facility with the remaining proceeds used for general corporate purposes. | |||||||||||||
Springerville Coal Handling Facilities Lease Purchase Commitment | Tax-Exempt Fixed Rate Bonds | |||||||||||||
In April 2015, upon the expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million, bringing its total ownership of the assets to 100%. With the completion of this purchase, Salt River Project Agricultural Improvement and Power District (SRP) is obligated to purchase a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State Generation and Transmission Association, Inc. (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. TEP expects SRP to complete its purchase commitment in the second quarter 2015. Tri-State has until April 2016 to elect an option. At March 31, 2015, no amounts have been recorded on TEP’s balance sheet for commitments from either SRP or Tri-State. | In March 2013, the Industrial Development Authority of Pima County, Arizona issued approximately $91 million aggregate principal amount of unsecured tax-exempt Industrial Development Revenue Bonds (IDRBs) for the benefit of TEP. The bonds bear interest at a fixed rate of 4.0%, mature in September 2029, and may be redeemed at par on or after March 2023. The proceeds from the sale of the bonds were deposited with a trustee to retire approximately $91 million of 6.375% unsecured tax- exempt bonds in April 2013. | |||||||||||||
UNSECURED BOND ISSUANCES AND REDEMPTIONS | ||||||||||||||
In January 2015, amounts borrowed under the 2014 Credit Agreement term loan portion were used to purchase $130 million aggregate principal amount of unsecured Industrial Development Revenue Bonds (IDRBs) issued in June 2008 by the Industrial Development Authority of Pima County for the benefit of TEP. These multi-modal bonds currently bear interest at a fixed rate of 5.75% and mature in September 2029. TEP did not cancel the purchased bonds and had not remarketed them as of March 31, 2015; therefore, they are not reflected as debt on the balance sheet. | Tax-Exempt Variable Rate Bonds and Interest Rate Swap | |||||||||||||
In February 2015, TEP issued and sold $300 million aggregate principal amount of its senior unsecured notes bearing interest at the fixed rate of 3.05% and maturing March 15, 2025. TEP may redeem the notes prior to December 15, 2024, with a make-whole premium plus accrued interest. On or after December 15, 2024, TEP may redeem the notes at par plus accrued interest. Interest on the notes will be payable semi-annually on each March 15 and September 15, beginning September 15, 2015, and at maturity. | In November 2013, the Industrial Development Authority of Apache County, Arizona issued $100 million of tax-exempt, variable rate IDRBs for the benefit of TEP, due April 2032. The lender resets the interest rate monthly based on a percentage of an index rate equal to one-month LIBOR plus a bank margin rate. In 2014, the average monthly variable rate was 0.87% and ranged from 0.85% to 0.95%. In 2013, the average monthly variable rate was 0.95%. These bonds are multi-modal bonds, and the initial term is set at five years through November 2018, at which time the bonds will be subject to mandatory tender for purchase. Proceeds were deposited with a trustee to redeem $100 million variable rate bonds in December 2013. | |||||||||||||
In March 2015, TEP used the net proceeds from the sale to repay $215 million of revolving and term loans under its 2014 Credit Agreement and 2010 Credit Agreement. See Credit Agreements below. In April 2015, TEP used the remaining amount to pay a portion of the purchase price for its ownership interests in the Springerville Coal Handling Facilities. | Certain of TEP’s tax-exempt, variable rate bonds are supported by Letter of Credits (LOCs) issued under the 2010 Credit Agreement and TEP Reimbursement Agreement, see below. | |||||||||||||
CREDIT AGREEMENTS | The following table shows interest rates (exclusive of LOC and remarketing fees) on TEP’s weekly variable rate bonds, which are reset weekly by its remarketing agents: | |||||||||||||
2014 Credit Agreement | ||||||||||||||
In March 2015, net proceeds from the sale of senior unsecured notes were used to repay the 2014 Credit Agreement’s $70 million outstanding revolver borrowings and $130 million outstanding term loan. The $130 million term loan portion cannot be reborrowed per the terms of the agreement. See Unsecured Bond Issuances and Redemptions above. | ||||||||||||||
As of March 31, 2015, there was $70 million available under the revolving credit facility of the 2014 Credit Agreement. As of May 4, 2015, TEP had nothing available under the 2014 Credit Agreement revolving credit facility. | Years Ended December 31, | |||||||||||||
2010 Credit Agreement | 2014 | 2013 | 2012 | |||||||||||
Interest rates and fees under the 2010 Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. With Moody’s Investors Service, Inc. (Moody’s) increase to TEP’s credit rating in February 2015, the interest rate currently in effect on borrowings decreased to LIBOR plus 1.00% for Eurodollar loans or Alternate Base Rate plus 0.00% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million Letter of Credit (LOC) facility decreased to 1.00%. | Interest Rates on Bonds | |||||||||||||
Average Interest Rate | 0.08% | 0.10% | 0.17% | |||||||||||
In March 2015, net proceeds from the sale of senior unsecured notes were used to repay $15 million of revolver borrowings outstanding. See Unsecured Bond Issuances and Redemptions above. | Range of Average Weekly Rates | .05% - 0.13% | 0.06% - 0.25% | 0.06% - 0.26% | ||||||||||
As of March 31, 2015, there was $200 million available under the revolving credit facility of the 2010 Credit Agreement. As of May 4, 2015, TEP had $142 million available under the 2010 Credit Agreement revolving credit facility. | In September 2014, an interest rate swap TEP entered into in August 2009, expired. The interest rate swap had the economic effect of converting $50 million of variable rate bonds to a fixed rate of 2.4% from September 2009 to September 2014. | |||||||||||||
2010 TEP REIMBURSEMENT AGREEMENT | TEP MORTGAGE INDENTURE | |||||||||||||
The 2010 TEP Reimbursement Agreement supports $37 million aggregate principal amount of variable rate tax-exempt bonds and includes fees payable on the aggregate outstanding amount. The rate currently in effect decreased to 0.75% per annum after credit rating upgrade in February 2015. | Prior to November 2013, the 2010 Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in mortgage bonds issued under the 1992 Mortgage. As a result of a credit rating upgrade, in October 2013, TEP canceled $423 million in mortgage bonds and discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the 2010 Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured. | |||||||||||||
COVENANT COMPLIANCE | CREDIT AGREEMENTS | |||||||||||||
At March 31, 2015, we were in compliance with the terms of our loan and credit agreements. | 2014 Credit Agreement | |||||||||||||
In December 2014, TEP entered into an unsecured credit agreement (2014 Credit Agreement). The 2014 Credit Agreement provides for a $130 million term loan commitment and a $70 million revolving credit commitment. Any amounts borrowed under the revolving credit commitment can be used for general corporate purposes. Amounts borrowed under the term loan can only be used to purchase certain tax-exempt bonds in lieu of redemption. All loans made pursuant to the term loan commitment and the revolving credit commitment will be due and payable in November 2015, the termination date of the 2014 Credit Agreement. | ||||||||||||||
In January 2015, amounts borrowed under the term loan commitment were used to purchase $130 million aggregate principal amount of unsecured IDRBs issued in June 2008 for the benefit of TEP. These multi-modal bonds currently bear interest at a fixed rate of 5.750% and mature in September 2029. At December 31, 2014, the bonds are classified as Long-Term Debt on TEP’s balance sheet. | ||||||||||||||
Loans under the 2014 Credit Agreement bear interest at a variable interest rate consisting of a spread over LIBOR or Alternate Base Rate. Alternate Base Rate is equal to the greater of (i) issuing bank’s reference rate, (ii) the federal funds rate plus 1/2 of 1% or (iii) adjusted LIBOR for an interest period of one month plus 0.750%. The interest rate in effect on borrowings is LIBOR plus 0.750% for Eurodollar loans or Alternate Base Rate for Alternate Base Rate loans. | ||||||||||||||
At December 31, 2014, TEP had a $70 million loan balance under the revolving credit facility and no borrowings under the term loan portion of the 2014 Credit Agreement. The revolving loan balance was included in Current Liabilities on TEP’s balance sheets. At December 31, 2014, there was nothing available under the revolving credit facility and $130 million available under the term loan for the 2014 Credit Agreement. As of January 30, 2015, TEP had a $130 million term loan balance outstanding under the 2014 Credit Agreement and a $70 million revolving loan balance. | ||||||||||||||
2010 Credit Agreement | ||||||||||||||
TEP’s core credit facility, which was entered into in 2010 and amended in 2011 (2010 Credit Agreement), has an expiration date of November 2016, and will continue to provide TEP with access to $200 million of revolving credit and $82 million in LOCs supporting variable-rate tax-exempt bonds. | ||||||||||||||
Interest rates and fees under the 2010 Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus 1.125% for Eurodollar loans or Alternate Base Rate plus 0.125% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million LOC facility is 1.125%. | ||||||||||||||
At December 31, 2014, TEP had $15 million in borrowings and $1 million outstanding in LOCs issued under the revolving credit facility for the 2010 Credit Agreement. At December 31, 2013, TEP had no borrowings and $1 million outstanding in LOCs issued under the revolving credit facility for the 2010 Credit Agreement. At December 31, 2014, there was $185 million available under the revolving credit facility for the 2010 Credit Agreement. The revolving loan balance was included in Current Liabilities on TEP’s balance sheets. The outstanding LOCs are not shown as liabilities on TEP’s balance sheets. As of January 30, 2015, TEP had $170 million available under the 2010 Credit Agreement revolving credit facility. | ||||||||||||||
2010 TEP REIMBURSEMENT AGREEMENT | ||||||||||||||
A $37 million LOC was issued pursuant to the 2010 TEP Reimbursement Agreement. The LOC supports $37 million aggregate principal amount of variable rate tax-exempt bonds that were issued on behalf of TEP in December 2010. In February 2014, TEP amended the agreement to extend the LOC expiration date from 2014 to 2019. Fees are payable on the aggregate outstanding amount of the LOC at a rate of 1.00% per annum. | ||||||||||||||
COVENANT COMPLIANCE | ||||||||||||||
The 2014 Credit Agreement, 2010 Credit Agreement, 2010 TEP Reimbursement Agreement, 2013 Covenants Agreement, and certain of our long-term debt agreements contain restrictive covenants, including restrictions on additional indebtedness, liens to secure indebtedness, mergers, sales of assets, transactions with affiliates, and restricted payments. | ||||||||||||||
At December 31, 2014, we were in compliance with the terms of our long-term debt, 2014 Credit Agreement, 2010 Credit Agreement, 2013 Covenants Agreement, and the 2010 TEP Reimbursement Agreement. | ||||||||||||||
CAPITAL LEASE OBLIGATIONS | ||||||||||||||
In January 2015, TEP reduced its capital lease obligations through the scheduled purchase payment for Springerville Unit 1 of $43 million and scheduled payments on other leases of $9 million. | ||||||||||||||
Springerville Unit 1 Capital Lease Purchases | ||||||||||||||
The Springerville Unit 1 Leases had an initial term to January 2015, and included a fair market value purchase option at the end of the initial lease term. | ||||||||||||||
In December 2014, TEP purchased a 10.6% leased interest in Springerville Unit 1, representing 41 MW of capacity, for $20 million, the appraised value. Upon purchase, TEP reduced Capital Lease Obligations on its balance sheet for the purchase price. In January 2015, TEP purchased leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million, the appraised value. | ||||||||||||||
With the completion of these lease option purchases, TEP owns 49.5% of Springerville Unit 1, or 192 MW of capacity. Furthermore, TEP is obligated to operate the unit for the Third-Party Owners under an existing facility support agreement. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses for the unit in the amount of approximately $1.5 million per month and their share of capital expenditures, which are approximately $7 million in 2015. See Note 6 of Notes to Consolidated Financial Statements. | ||||||||||||||
Springerville Coal Handling Facilities 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 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. | ||||||||||||||
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 December 31, 2014. | ||||||||||||||
Springerville Common Facilities Leases | ||||||||||||||
The Springerville Common Facilities Leases have an initial term to December 2017 for one lease and January 2021 for the other two leases, subject to optional renewal periods of two or more years through 2025. Instead of extending the leases, TEP may exercise a fixed-price purchase provision. The fixed prices for the acquisition of the common facilities are $38 million in 2017 and $68 million in 2021. | ||||||||||||||
TEP 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 and Common Facilities Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri-State will then be obligated to either: buy a portion of these facilities; or continue making payments to TEP for the use of these facilities. | ||||||||||||||
Lease Debt and Equity | ||||||||||||||
Investments in Springerville Lease Debt and Equity | ||||||||||||||
In January 2013, TEP received the final maturity payment of $9 million on the investment in Springerville Unit 1 lease debt. TEP also held an undivided equity ownership interest in the Springerville Unit 1 Leases totaling $36 million at December 31, 2013. At December 31, 2014, $36 million was transferred from Lease Equity Investment to Plant in Service on TEP’s balance sheet. | ||||||||||||||
Interest Rate Swap—Springerville Common Facilities Lease Debt | ||||||||||||||
TEP’s interest rate swap hedges the floating interest rate risk associated with the Springerville Common Facilities lease debt. Interest on the lease debt is payable at six-month LIBOR plus a credit spread. The applicable spread was 1.75% at December 31, 2014 and December 31, 2013. | ||||||||||||||
The swap has the effect of fixing the interest rates on the amortizing principal balances as follows: | ||||||||||||||
Fixed Rate | LIBOR Spread | |||||||||||||
Lease Debt Outstanding at December 31, 2014 | ||||||||||||||
Notional Amount $32 million - Effective Date June 2006 | 5.77% | 1.75% | ||||||||||||
TEP recorded the interest rate swap as a cash flow hedge for financial reporting purposes. See Note 10 of Notes to Consolidated Financial Statements. | ||||||||||||||
DEBT MATURITIES | ||||||||||||||
Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates: | ||||||||||||||
Long-Term Debt | Capital Lease | Total | ||||||||||||
Maturities (1) | Obligations | |||||||||||||
Millions of Dollars | ||||||||||||||
2015 | $ | — | $ | 188 | $ | 188 | ||||||||
2016 | 79 | 16 | 95 | |||||||||||
2017 | — | 18 | 18 | |||||||||||
2018 | 100 | 11 | 111 | |||||||||||
2019 | 37 | 12 | 49 | |||||||||||
Total 2015 - 2019 | 216 | 245 | 461 | |||||||||||
Thereafter | 1,159 | 18 | 1,177 | |||||||||||
Less: Imputed Interest | — | (20 | ) | (20 | ) | |||||||||
Total | $ | 1,375 | $ | 243 | $ | 1,618 | ||||||||
-1 | $115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to the 2010 Credit Agreement, which expires in November 2016, and the TEP 2010 Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the 2010 Credit Agreement and the 2010 Reimbursement Agreement. TEP’s 2013 tax-exempt variable rate IDRBs, which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in 2018. The repayment of TEP Unsecured Notes is not reduced by the remaining $2 million original issue discount. |
COMMITMENTS_CONTINGENCIES_AND_
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS | COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS | COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
COMMITMENTS | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
In addition to those reported in our 2014 Annual Report on Form 10-K, TEP entered into the following long-term commitments through March 31, 2015: | COMMITMENTS | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fuel, Including Transportation | $ | 1 | $ | 2 | $ | 2 | $ | 2 | $ | 2 | $ | 47 | $ | 56 | ||||||||||||||||||||||||||||||||||||||||||||
Purchased Power | 30 | 11 | — | — | — | — | 41 | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total Purchase Commitments | $ | 31 | $ | 13 | $ | 2 | $ | 2 | $ | 2 | $ | 47 | $ | 97 | Fuel, Including Transportation | $ | 76 | $ | 78 | $ | 76 | $ | 49 | $ | 49 | $ | 285 | $ | 613 | |||||||||||||||||||||||||||||
Purchased Power | 22 | 7 | — | — | — | — | 29 | |||||||||||||||||||||||||||||||||||||||||||||||||||
CONTINGENCIES | Transmission | 6 | 6 | 6 | 6 | 4 | 16 | 44 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Navajo Generating Station Lease Extension | Renewable Power Purchase Agreements | 45 | 45 | 45 | 45 | 44 | 565 | 789 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Navajo Generating Station (Navajo) is located on a site that is leased from the Navajo Nation with an initial lease term through 2019. The Navajo Nation signed a lease amendment that would extend the lease from 2019 through 2044. The participants in Navajo, including TEP, have not signed the lease amendment. Certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations are ongoing, and all parties will likely agree to the terms. To become effective, this lease amendment must be signed by all of the participants, approved by the Department of the Interior, and is subject to environmental reviews. TEP owns 7.5% of Navajo. In the first quarter of 2015, TEP recorded additional estimated lease expense of approximately $1 million with the expectation that the lease amendment will become effective. At March 31, 2015, TEP’s balance sheet reflects a total liability related to the lease amendment of $3 million recorded in Deferred Credits and Other Liabilities—Other. | RES Performance-Based Incentives | 8 | 8 | 8 | 8 | 8 | 76 | 116 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Claims Related to Springerville Generating Station Unit 1 | Operating Leases: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
On November 7, 2014, the Springerville Unit 1 Third-Party Owners filed a complaint (FERC Action) against TEP at the FERC alleging that TEP had not agreed to wheel power and energy for the Third-Party Owners in the manner specified in the Springerville Unit 1 facility support agreement between TEP and the Third-Party Owners and for the cost specified by the Third-Party Owners. The Third-Party Owners requested an order from the FERC requiring such wheeling of the Third-Party Owners’ energy from their Springerville Unit 1 interests beginning on January 1, 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. On December 3, 2014, TEP filed an answer to the FERC Action denying the allegations and requesting that the FERC dismiss the complaint. On February 19, 2015, the FERC issued an order denying the Third-Party Owners complaint. On March 23, 2015, the Third-Party Owners filed a request for rehearing in the FERC Action. On April 7, 2015, TEP filed an answer in response to the request for rehearing. The FERC has not yet ruled on the request for rehearing. | Land Easements and Rights-of-Way | 2 | 1 | 1 | 1 | 2 | 77 | 84 | ||||||||||||||||||||||||||||||||||||||||||||||||||
On December 19, 2014, the Third-Party Owners filed a complaint against TEP in the Supreme Court of the State of New York, New York County (New York Action), alleging, among other things, that TEP has refused to comply with the Third-Party Owners’ instructions to schedule their entitlement share of power and energy, that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases, that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action, and that TEP has breached fiduciary duties claimed to be owed to the Third-Party Owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial and the Third-Party Owners’ fees and expenses. On February 20, 2015, TEP filed a motion to dismiss in the New York Action that requested that the court dismiss various counts of the complaint. On March 20, 2015, the Third-Party Owners filed a first amended complaint which includes all the counts that were in the original complaint except those alleging that TEP refused to comply with the Third-Party Owners instructions to schedule power and energy and to specify the level of fuel and fuel handling services, which have been dropped. The amended complaint also includes new counts alleging that TEP has failed to pay the Third-Party Owners approximately $71 million in liquidated damages they allege they are owed (see following paragraph), that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired, that TEP has converted the Third-Party Owners’ water rights and that TEP has been unjustly enriched as a result, and that TEP has breached the lease transaction documents by refusing to pay certain of the Third-Party Owners’ claimed expenses. On April 20, 2015, TEP filed a motion to compel arbitration and to dismiss or stay certain counts of the amended complaint in the New York Action. | Operating Leases Other | 1 | 1 | 1 | 1 | 1 | 5 | 10 | ||||||||||||||||||||||||||||||||||||||||||||||||||
On December 22, 2014, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent a notice to TEP that alleges that TEP has defaulted under the Third-Party Owners’ leases. The notice states that the Owner Trustees, as Lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totaling approximately $71 million. On January 26, 2015, Wilmington Trust Company sent a second notice repeating the allegations in the December 22, 2014 notice. In a letter to Wilmington Trust Company, TEP denied the allegations in the second notice. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
On April 20, 2015, TEP filed a demand for arbitration with the American Arbitration Association seeking an award of the Third-Party Owners share of unreimbursed expense and capital expenditures for Springerville Unit 1. As of March 31, 2015, TEP has billed the Third-Party Owners approximately $6 million for their pro-rata share of Springerville Unit 1 expenses and less than $0.5 million for their pro-rata share of capital costs, none of which has been paid as of May 4, 2015. | Total Purchase Commitments | $ | 160 | $ | 146 | $ | 137 | $ | 110 | $ | 108 | $ | 1,024 | $ | 1,685 | |||||||||||||||||||||||||||||||||||||||||||
TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the United States District Court of Colorado against the Office of Surface Mining (OSM) challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act (NEPA) violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The Court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico, where this matter is now proceeding. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and San Juan. TEP cannot currently predict the outcome of this matter or the range of its potential impact. | Fuel | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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. The parties exchanged settlement proposals in January and February 2015, and have agreed to have the matter stayed until June 1, 2015 to make continued progress toward a final agreement that would resolve this matter without further litigation. A final consent decree version is currently being circulated for signature by all of the parties. | TEP has long-term contracts for the purchase and delivery of coal with various expiration dates through 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these contracts include a price adjustment clause that will affect the future cost. TEP expects to spend more than the minimum purchase obligations to meet its fuel requirements. TEP’s fuel costs are recoverable from customers through the PPFAC. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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. TEP cannot predict the final outcome or timing of resolution of this claim. | TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These contracts expire in various years between 2017 and 2040. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 $52 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability recorded was $23 million at March 31, 2015 and $22 million at December 31, 2014. | Purchased Power and Transmission | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 final reclamation costs, as a component of fuel cost, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers. | TEP has agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity payments and energy payments based on actual power taken under the contracts. These contracts expire through 2017. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table are based on projected market prices as of December 31, 2014. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Discontinued Transmission Project | TEP has agreements with other utilities to provide transmission services. These contracts expire in various years between 2018 and 2028. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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-Kilo-volt (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 maintain the Certificate of Environmental Compatibility (CEC) previously granted by the ACC for this project in contemplation of using the route, or a portion thereof, 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 | TEP’s purchased power and transmission costs are recoverable from customers through the PPFAC mechanisms. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 March 31, 2015, there have been no such payment defaults under any of the remote generating station agreements. TEP’s joint participation agreements for the San Juan, Navajo, Four Corners and Luna generating facilities expire in 2019 through 2046. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
ENVIRONMENTAL MATTERS | Renewable Power Purchase Agreements and RES Performance-Based Incentives | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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. | TEP has entered into 20 year Renewable PPAs which require TEP to purchase 100% of the output of certain renewable energy generation facilities that have achieved commercial operation. These agreements have various expiration dates through 2034. TEP has entered into additional long-term renewable PPAs to comply with RES requirements; however, TEP’s obligation to purchase power under these agreements does not begin until the facilities are operational. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 2 of Notes to Consolidated Financial Statements. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Coal Combustion Residuals Regulations | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
In April 2015, the EPA issued a final rule requiring all coal ash and other coal combustion residuals to be treated as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) while allowing for the continued recycling of coal ash. TEP is in the process of evaluating the final impacts of the rule on our coal fired generation. However, TEP does not anticipate significant impacts to our existing facilities where coal combustion residual are managed. The additional requirements would apply to lateral expansion of those existing landfills or to any new landfill. | TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed- upon intervals (usually quarterly) based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 2 of Notes to Consolidated Financial Statements. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 Standards (MATS) rules, additional emission control equipment would have been required by April 2015. However, 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: | Operating Leases | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Our operating lease expense is primarily for rail cars, office facilities, land easements, and rights-of-way with varying terms, provisions, and expiration dates. TEP’s operating lease expense totaled $3 million in 2014, and $2 million in each of 2013 and 2012. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Mercury Emissions Control Costs: | Navajo | Springerville(1) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | CONTINGENCIES | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capital Expenditures | $ | 1 | $ | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual O&M Expenses | 1 | 1 | Navajo Generating Station Lease Extension | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
(1) | Total capital expenditures and annual O&M expenses represent amounts for Springerville Units 1 & 2, with estimated costs split equally between the two units. In January 2015, TEP completed the purchase of 49.5% of Springerville Unit 1. With the completion of the purchase, Third Party Owners are 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. | Navajo Generating Station (Navajo) is located on a site that is leased from the Navajo Nation with an initial lease term through 2019. The Navajo Nation signed a lease amendment that would extend the lease from 2019 through 2044. The participants in Navajo, including TEP, have not signed the lease amendment. Certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations are ongoing, and all parties will likely agree to the terms. To become effective, this lease amendment must be signed by all of the participants, approved by the Department of the Interior, and is subject to environmental reviews. TEP owns 7.5% of Navajo and, in December 2014, recorded additional lease expense of approximately $2 million related to the lease extension in Deferred Credits and Other Liabilities—Other on TEP’s balance sheet. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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. | Claims Related to Springerville Generating Station Unit 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 land leased from the Navajo Nation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants. | On November 7, 2014, the Springerville Unit 1 Third-Party Owners filed a complaint (FERC Action) against TEP at the FERC alleging that TEP had not agreed to wheel power and energy for the Third-Party Owners in the manner specified in the Springerville Unit 1 facility support agreement between TEP and the Third-Party Owners and for the cost specified by the Third-Party Owners. The Third-Party Owners requested an order from the FERC requiring such wheeling of the Third-Party Owners’ energy from their Springerville Unit 1 interests beginning on January 1 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. On December 3, 2014, TEP filed an answer to the FERC Action denying the allegations and requesting that the FERC dismiss the complaint. On February 19, 2015, the FERC issued an order denying the Third-Party Owners complaint. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 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. These BART provisions do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018. TEP cannot predict the ultimate outcome of these matters. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
TEP’s estimated costs involved in meeting these rules are: | On December 19, 2014, the Third-Party Owners filed a complaint against TEP in the Supreme Court of the State of New York, New York County (New York Action), alleging, among other things, that TEP has refused to comply with the Third-Party Owners’ instructions to schedule their entitlement share of power and energy, that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases, that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action and that TEP has breached fiduciary duties claimed to be owed to the Third- Party Owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial and the Third-Party Owners’ fees and expenses. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
On December 22, 2014, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent a notice to TEP that alleges that TEP has defaulted under the Third-Party Owners’ leases. The notice states that the Owner Trustees, as Lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totaling approximately $71 million. On January 26, 2015, Wilmington Trust Company sent a second notice repeating the allegations in the December 22, 2014 notice. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated NOx Emissions Control Costs: | Navajo | San | Four | Sundt(4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Juan(1) | Corners(3) | TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capital Expenditures | $ | 28 | $ | 37 | $ | 44 | $ | 12 | Claims Related to San Juan Generating Station | |||||||||||||||||||||||||||||||||||||||||||||||||
Annual O&M Expenses | 1 | 1 | 2 | 6-May | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(1) | In August 2014, the EPA published a final Federal Implementation Plan (FIP) 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. The final BART includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA which option will be implemented. 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 $28 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 revised State Implementation Plan (SIP) 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 February 2016. TEP owns 50% of Units 1 and 2 at San Juan. TEP expects its share of the cost to install SNCR technology on San Juan Unit 1 to be approximately $12 million. Additionally, the SIP approval references a New Source Review permit issued by the New Mexico Environment Department in November 2013 which, among other things, calls for balanced draft upgrades on San Juan Unit 1 to reduce particulate matter emissions. Public Service Company of New Mexico (PNM), the operator of San Juan, is currently installing SNCR and making the necessary balanced draft modifications to San Juan Unit 1. TEP’s share of the balanced draft upgrades is expected to be approximately $25 million for a total of $37 million in capital expenditures. TEP’s share of incremental annual operating costs for SNCR for San Juan Unit 1 is estimated at $1 million. Prior to the shutdown of any units at San Juan, PNM, the operator, must first obtain New Mexico Public Regulation Commission approval. At March 31, 2015, the net book value of TEP’s share in San Juan Unit 2 was $109 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC’s authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(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 and 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, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At March 31, 2015, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities. | 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the United States District Court of Colorado against the Office of Surface Mining (OSM) challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act (NEPA) violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The Court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico, where this matter is now proceeding. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and San Juan. TEP cannot currently predict the outcome of this matter or the range of its potential impact. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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. The parties exchanged settlement proposals in January and February 2015, and have agreed to have the matter stayed until March 31, 2015 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 continue with settlement negotiations. 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 $49 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $22 million at December 31, 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 final reclamation costs, as a component of fuel cost, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 maintain the Certificate of Environmental Compatibility (CEC) previously granted by the ACC for this project 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 December 31, 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 capitalized $11 million in 2014, $5 million in 2013, and $2 million in 2012 in construction costs to comply with environmental requirements. TEP expects to capitalize environmental compliance costs of $28 million in 2015 and $19 million in 2016. In addition, TEP recorded O&M expenses of $5 million in 2014, $8 million in 2013, and $15 million in 2012. TEP expects environmental O&M expenses to be $4 million in each of 2015 and 2016. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 Standards (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 owns 49.5% of Springerville Unit 1 with the close of the lease option purchases in December 2014 and January 2015; Third-Party Owners are responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP continues 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. 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 land leased from the Navajo Nation, 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. The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018. 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 | $ | 28 | $ | 37 | $ | 35 | $ | 12 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Annual O&M Expenses | 1 | 1 | 2 | 6-May | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
-1 | In August 2014, the EPA published a final FIP 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. The plant has until December 2019 to notify the EPA which option will be implemented. 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 $28 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 revised State Implementation Plan (SIP) 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) and Balance Draft technology on Units 1 and 4 by February 2016. Prior to the shutdown of any units at San Juan, Public Service Company of New Mexico (PNM), the operator, must first obtain New Mexico Public Regulation Commission approval. TEP owns 50% of San Juan Unit 2. At December 31, 2014, the net book value of TEP’s share in San Juan Unit 2 was $110 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC’s authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
-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 and 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, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At December 31, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities. |
EMPLOYEE_BENEFIT_PLANS
EMPLOYEE BENEFIT PLANS | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||||||||||||||||||||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS | ||||||||||||||||||||||||||||||||||||||||
Net periodic benefit plan cost includes the following components: | ||||||||||||||||||||||||||||||||||||||||||
PENSION BENEFIT PLANS | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree Benefits | We sponsor two noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We fund the pension plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) regulations. | ||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||||||||||||||||||
2015 | 2014 | 2015 | 2014 | We also maintain a Supplemental Executive Retirement Plan (SERP) for executive management. | ||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Service Cost | $ | 3 | $ | 2 | $ | 1 | $ | 1 | OTHER RETIREE BENEFIT PLANS | |||||||||||||||||||||||||||||||||
Interest Cost | 4 | 4 | 1 | — | ||||||||||||||||||||||||||||||||||||||
Expected Return on Plan Assets | (6 | ) | (5 | ) | — | — | TEP provides limited health care and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate. | |||||||||||||||||||||||||||||||||||
Actuarial Loss Amortization | 2 | 1 | — | — | ||||||||||||||||||||||||||||||||||||||
TEP funds its other retiree benefits for classified employees through a Voluntary Employee Beneficiary Association (VEBA). TEP contributed $3 million in each of 2014, 2013 and 2012 to the VEBA. Other retiree benefits for unclassified employees are self-funded. | ||||||||||||||||||||||||||||||||||||||||||
Net Periodic Benefit Cost | $ | 3 | $ | 2 | $ | 2 | $ | 1 | ||||||||||||||||||||||||||||||||||
TEP’s other retiree benefit plan was amended in 2012 to increase the participant contributions for classified employees who retire after February 1, 2014. The effect on the benefit obligation was less than $1 million. | ||||||||||||||||||||||||||||||||||||||||||
REGULATORY RECOVERY | ||||||||||||||||||||||||||||||||||||||||||
We record changes in our non-SERP pension plans and other retiree benefit plan, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in the rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income since SERP expense is not currently recoverable in rates. | ||||||||||||||||||||||||||||||||||||||||||
The pension and other retiree benefit related amounts (excluding tax balances) included on our balance sheet are: | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree | |||||||||||||||||||||||||||||||||||||||||
Benefits | ||||||||||||||||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Regulatory Pension Asset Included in Other Regulatory Assets | $ | 117 | $ | 71 | $ | 9 | $ | 4 | ||||||||||||||||||||||||||||||||||
Accrued Benefit Liability Included in Accrued Employee Expenses | (1 | ) | (1 | ) | (2 | ) | (2 | ) | ||||||||||||||||||||||||||||||||||
Accrued Benefit Liability Included in Pension and Other Retiree Benefits | (71 | ) | (23 | ) | (67 | ) | (62 | ) | ||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Loss (related to SERP) | 5 | 2 | — | — | ||||||||||||||||||||||||||||||||||||||
Net Amount Recognized | $ | 50 | $ | 49 | $ | (60 | ) | $ | (60 | ) | ||||||||||||||||||||||||||||||||
OBLIGATIONS AND FUNDED STATUS | ||||||||||||||||||||||||||||||||||||||||||
We measured the actuarial present values of all pension benefit obligations and other retiree benefit plans at December 31, 2014 and December 31, 2013. The table below includes all of TEP’s plans. All plans have projected benefit obligations in excess of fair value of plan assets for each period presented. The status of our pension benefit and other retiree benefit plans are summarized below: | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree Benefits | |||||||||||||||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Change in Projected Benefit Obligation | ||||||||||||||||||||||||||||||||||||||||||
Benefit Obligation at Beginning of Year | $ | 330 | $ | 357 | $ | 74 | $ | 77 | ||||||||||||||||||||||||||||||||||
Actuarial (Gain) Loss | 67 | (35 | ) | 5 | (5 | ) | ||||||||||||||||||||||||||||||||||||
Interest Cost | 16 | 14 | 3 | 3 | ||||||||||||||||||||||||||||||||||||||
Service Cost | 10 | 11 | 4 | 3 | ||||||||||||||||||||||||||||||||||||||
Benefits Paid | (16 | ) | (17 | ) | (5 | ) | (4 | ) | ||||||||||||||||||||||||||||||||||
Projected Benefit Obligation at End of Year | 407 | 330 | 81 | 74 | ||||||||||||||||||||||||||||||||||||||
Change in Plan Assets | ||||||||||||||||||||||||||||||||||||||||||
Fair Value of Plan Assets at Beginning of Year | 307 | 275 | 10 | 7 | ||||||||||||||||||||||||||||||||||||||
Actual Return on Plan Assets | 35 | 27 | 1 | 1 | ||||||||||||||||||||||||||||||||||||||
Benefits Paid | (16 | ) | (17 | ) | (5 | ) | (4 | ) | ||||||||||||||||||||||||||||||||||
Employer Contributions(1) | 9 | 22 | 6 | 6 | ||||||||||||||||||||||||||||||||||||||
Fair Value of Plan Assets at End of Year | 335 | 307 | 12 | 10 | ||||||||||||||||||||||||||||||||||||||
Funded Status at End of Year | $ | (72 | ) | $ | (23 | ) | $ | (69 | ) | $ | (64 | ) | ||||||||||||||||||||||||||||||
(1) | In 2015, TEP expects to contribute $23 million to the pension plans. | |||||||||||||||||||||||||||||||||||||||||
The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree Benefits | |||||||||||||||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Net Loss | $ | 118 | $ | 74 | $ | 11 | $ | 6 | ||||||||||||||||||||||||||||||||||
Prior Service Cost (Benefit) | 4 | — | (2 | ) | (2 | ) | ||||||||||||||||||||||||||||||||||||
The accumulated benefit obligation aggregated for all pension plans is $365 million at December 31, 2014 and $297 million at December 31, 2013. | ||||||||||||||||||||||||||||||||||||||||||
Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets: | ||||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Accumulated Benefit Obligation at End of Year | $ | 365 | $ | 13 | ||||||||||||||||||||||||||||||||||||||
Fair Value of Plan Assets at End of Year | 335 | — | ||||||||||||||||||||||||||||||||||||||||
Only the SERP, which is unfunded, had accumulated benefit obligations in excess of plan assets at December 31, 2013. Due to decreases in discount rates, and changes in mortality projections which reflect a longer life expectancy, all of our plans had accumulated benefit obligations in excess of plan assets at December 31, 2014. | ||||||||||||||||||||||||||||||||||||||||||
Net periodic benefit plan cost includes the following components: | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree Benefits | |||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||||
Service Cost | $ | 10 | $ | 11 | $ | 9 | $ | 4 | $ | 3 | $ | 3 | ||||||||||||||||||||||||||||||
Interest Cost | 16 | 14 | 15 | 3 | 3 | 3 | ||||||||||||||||||||||||||||||||||||
Expected Return on Plan Assets | (21 | ) | (19 | ) | (17 | ) | (1 | ) | (1 | ) | — | |||||||||||||||||||||||||||||||
Actuarial Loss Amortization | 3 | 8 | 7 | — | — | — | ||||||||||||||||||||||||||||||||||||
Net Periodic Benefit Cost | $ | 8 | $ | 14 | $ | 14 | $ | 6 | $ | 5 | $ | 6 | ||||||||||||||||||||||||||||||
Approximately 20% of the net periodic benefit cost was capitalized as a cost of construction and the remainder was included in income. | ||||||||||||||||||||||||||||||||||||||||||
The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows: | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||||||
Regulatory | QOCI | Regulatory | AOCI | Regulatory | AOCI | |||||||||||||||||||||||||||||||||||||
Asset | Asset | Asset | ||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Current Year Actuarial (Gain) Loss | $ | 49 | $ | 3 | $ | (42 | ) | $ | (1 | ) | $ | 28 | $ | 1 | ||||||||||||||||||||||||||||
Amortization of Actuarial Gain (Loss) | (3 | ) | — | (8 | ) | — | (7 | ) | — | |||||||||||||||||||||||||||||||||
Total Recognized (Gain) Loss | $ | 46 | $ | 3 | $ | (50 | ) | $ | (1 | ) | $ | 21 | $ | 1 | ||||||||||||||||||||||||||||
Other Retiree Benefits | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||||||
Regulatory | Regulatory | Regulatory | ||||||||||||||||||||||||||||||||||||||||
Asset | Asset | Asset | ||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Current Year Actuarial (Gain) Loss | $ | 5 | $ | (6 | ) | $ | 2 | |||||||||||||||||||||||||||||||||||
For all pension plans, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. We will amortize $7 million estimated net loss and less than $0.5 million prior service credit from other regulatory assets and less than $0.5 million net loss and less than $0.5 million prior service cost from AOCI into net periodic benefit cost in 2015. Less than $0.5 million estimated net loss and less than $0.5 million prior service benefit for the other retiree benefit plan will be amortized from other regulatory assets into net periodic benefit cost in 2015. | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree | |||||||||||||||||||||||||||||||||||||||||
Benefits | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31, | ||||||||||||||||||||||||||||||||||||||||||
Discount Rate | 4.1 - 4.2% | 5.0% - 5.1% | 3.90% | 4.70% | ||||||||||||||||||||||||||||||||||||||
Rate of Compensation Increase | 3.00% | 3.00% | N/A | N/A | ||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree | |||||||||||||||||||||||||||||||||||||||||
Benefits | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||||
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||
Discount Rate | 5.0% - 5.1% | 4.1% - 4.1% | 4.9% - 5.0% | 4.70% | 3.80% | 4.70% | ||||||||||||||||||||||||||||||||||||
Rate of Compensation Increase | 3.00% | 3.00% | 3.00% | N/A | N/A | N/A | ||||||||||||||||||||||||||||||||||||
Expected Return on Plan Assets | 7.00% | 7.00% | 7.00% | 7.00% | 7.00% | 7.00% | ||||||||||||||||||||||||||||||||||||
Net periodic benefit cost is subject to various assumptions and determinations, such as the discount rate, the rate of compensation increase, and the expected return on plan assets. | ||||||||||||||||||||||||||||||||||||||||||
We use a combination of sources in selecting the expected long-term rate-of-return-on-assets assumption, including an investment return model. The model used provides a “best-estimate” range over 20 years from the 25th percentile to the 75th percentile. The model, used as a guideline for selecting the overall rate-of-return-on-assets assumption, is based on forward looking return expectations only. The above method is used for all asset classes. | ||||||||||||||||||||||||||||||||||||||||||
Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. The assumed health care cost trend rates follow: | ||||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Health Care Cost Trend Rate Assumed for Next Year | 6.7 | % | 6.7 | % | ||||||||||||||||||||||||||||||||||||||
Ultimate Health Care Cost Trend Rate Assumed | 4.5 | % | 4.5 | % | ||||||||||||||||||||||||||||||||||||||
Year that the Rate Reaches the Ultimate Trend Rate | 2027 | 2027 | ||||||||||||||||||||||||||||||||||||||||
Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the December 31, 2014, amounts: | ||||||||||||||||||||||||||||||||||||||||||
One Percentage | One Percentage | |||||||||||||||||||||||||||||||||||||||||
Point Increase | Point Decrease | |||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Effect on Total Service and Interest Cost Components | $ | 1 | $ | 1 | ||||||||||||||||||||||||||||||||||||||
Effect on Retiree Benefit Obligation | 7 | 6 | ||||||||||||||||||||||||||||||||||||||||
PENSION PLAN AND OTHER RETIREE BENEFIT ASSETS | ||||||||||||||||||||||||||||||||||||||||||
Pension Assets | ||||||||||||||||||||||||||||||||||||||||||
We calculate the fair value of plan assets on December 31, the measurement date. Pension plan asset allocations, by asset category, on the measurement date were as follows: | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Asset Category | ||||||||||||||||||||||||||||||||||||||||||
Equity Securities | 48 | % | 50 | % | ||||||||||||||||||||||||||||||||||||||
Fixed Income Securities | 43 | % | 40 | % | ||||||||||||||||||||||||||||||||||||||
Real Estate | 7 | % | 7 | % | ||||||||||||||||||||||||||||||||||||||
Other | 2 | % | 3 | % | ||||||||||||||||||||||||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||||||||||||||||||||||||
The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy: | ||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements of Pension Assets | ||||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Quoted Prices in | Significant Other | Significant | Total | |||||||||||||||||||||||||||||||||||||||
Active Markets | Observable Inputs | Unobservable | ||||||||||||||||||||||||||||||||||||||||
(Level 1) | (Level 2) | Inputs | ||||||||||||||||||||||||||||||||||||||||
(Level 3) | ||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Asset Category | ||||||||||||||||||||||||||||||||||||||||||
Cash Equivalents | $ | 1 | $ | — | $ | — | $ | 1 | ||||||||||||||||||||||||||||||||||
Equity Securities: | ||||||||||||||||||||||||||||||||||||||||||
United States Large Cap | — | 82 | — | 82 | ||||||||||||||||||||||||||||||||||||||
United States Small Cap | — | 17 | — | 17 | ||||||||||||||||||||||||||||||||||||||
Non-United States | — | 61 | — | 61 | ||||||||||||||||||||||||||||||||||||||
Fixed Income | — | 143 | — | 143 | ||||||||||||||||||||||||||||||||||||||
Real Estate | — | 8 | 16 | 24 | ||||||||||||||||||||||||||||||||||||||
Private Equity | — | — | 7 | 7 | ||||||||||||||||||||||||||||||||||||||
Total | $ | 1 | $ | 311 | $ | 23 | $ | 335 | ||||||||||||||||||||||||||||||||||
Fair Value Measurements of Pension Assets | ||||||||||||||||||||||||||||||||||||||||||
31-Dec-13 | ||||||||||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Asset Category | ||||||||||||||||||||||||||||||||||||||||||
Cash Equivalents | $ | 1 | $ | — | $ | — | $ | 1 | ||||||||||||||||||||||||||||||||||
Equity Securities: | ||||||||||||||||||||||||||||||||||||||||||
United States Large Cap | — | 76 | — | 76 | ||||||||||||||||||||||||||||||||||||||
United States Small Cap | — | 16 | — | 16 | ||||||||||||||||||||||||||||||||||||||
Non-United States | — | 62 | — | 62 | ||||||||||||||||||||||||||||||||||||||
Fixed Income | — | 124 | — | 124 | ||||||||||||||||||||||||||||||||||||||
Real Estate | — | 7 | 14 | 21 | ||||||||||||||||||||||||||||||||||||||
Private Equity | — | — | 7 | 7 | ||||||||||||||||||||||||||||||||||||||
Total | $ | 1 | $ | 285 | $ | 21 | $ | 307 | ||||||||||||||||||||||||||||||||||
Level 1 cash equivalents are based on observable market prices and are comprised of the fair value of commercial paper, money market funds, and certificates of deposit. | ||||||||||||||||||||||||||||||||||||||||||
Level 2 investments comprise amounts held in commingled equity funds, United States bond funds, and real estate funds. Valuations are based on active market quoted prices for assets held by each respective fund. | ||||||||||||||||||||||||||||||||||||||||||
Level 3 real estate investments were valued using a real estate index value. The real estate index value was developed based on appraisals comprising 100% of real estate assets tracked by the index in 2014 and comprising 85% in 2013. | ||||||||||||||||||||||||||||||||||||||||||
Level 3 private equity funds are classified as funds-of-funds. They are valued based on individual fund manager valuation models. | ||||||||||||||||||||||||||||||||||||||||||
The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. | ||||||||||||||||||||||||||||||||||||||||||
Year Ended | ||||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Private Equity | Real Estate | Total | ||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Beginning Balance at January 1, 2014 | $ | 7 | $ | 14 | $ | 21 | ||||||||||||||||||||||||||||||||||||
Actual Return on Plan Assets: | ||||||||||||||||||||||||||||||||||||||||||
Assets Held at Reporting Date | 1 | 2 | 3 | |||||||||||||||||||||||||||||||||||||||
Purchases, Sales, and Settlements | (1 | ) | — | (1 | ) | |||||||||||||||||||||||||||||||||||||
Ending Balance at December 31, 2014 | $ | 7 | $ | 16 | $ | 23 | ||||||||||||||||||||||||||||||||||||
Year Ended | ||||||||||||||||||||||||||||||||||||||||||
December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||
Private Equity | Real Estate | Total | ||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Beginning Balance at January 1, 2013 | $ | 6 | $ | 13 | $ | 19 | ||||||||||||||||||||||||||||||||||||
Actual Return on Plan Assets: | ||||||||||||||||||||||||||||||||||||||||||
Assets Held at Reporting Date | 1 | 1 | 2 | |||||||||||||||||||||||||||||||||||||||
Ending Balance at December 31, 2013 | $ | 7 | $ | 14 | $ | 21 | ||||||||||||||||||||||||||||||||||||
Pension Plan Investments | ||||||||||||||||||||||||||||||||||||||||||
Investment Goals | ||||||||||||||||||||||||||||||||||||||||||
Asset allocation is the principal method for achieving each pension plan’s investment objectives while maintaining appropriate levels of risk. We consider the projected impact on benefit security of any proposed changes to the current asset allocation policy. The expected long-term returns and implications for pension plan sponsor funding are reviewed in selecting policies to ensure that current asset pools are projected to be adequate to meet the expected liabilities of the pension plans. We expect to use asset allocation policies weighted most heavily to equity and fixed income funds, while maintaining some exposure to real estate and opportunistic funds. Within the fixed income allocation, long-duration funds may be used to partially hedge interest rate risk. | ||||||||||||||||||||||||||||||||||||||||||
Risk Management | ||||||||||||||||||||||||||||||||||||||||||
We recognize the difficulty of achieving investment objectives in light of the uncertainties and complexities of the investment markets. We also recognize some risk must be assumed to achieve a pension plan’s long-term investment objectives. In establishing risk tolerances, the following factors affecting risk tolerance and risk objectives will be considered: plan status, plan sponsor financial status and profitability, plan features, and workforce characteristics. We have determined that the pension plans can tolerate some interim fluctuations in market value and rates of return in order to achieve long-term objectives. TEP tracks each pension plan’s portfolio relative to the benchmark through quarterly investment reviews. The reviews consist of a performance and risk assessment of all investment categories and on the portfolio as a whole. Investment managers for the pension plan may use derivative financial instruments for risk management purposes or as part of their investment strategy. Currency hedges may also be used for defensive purposes. | ||||||||||||||||||||||||||||||||||||||||||
Relationship between Plan Assets and Benefit Obligations | ||||||||||||||||||||||||||||||||||||||||||
The overall health of each plan will be monitored by comparing the value of plan obligations (both Accumulated Benefit Obligation and Projected Benefit Obligation) against the fair value of assets and tracking the changes in each. The frequency of this monitoring will depend on the availability of plan data, but will be no less frequent than annually via actuarial valuation. | ||||||||||||||||||||||||||||||||||||||||||
Target Allocation Percentages | ||||||||||||||||||||||||||||||||||||||||||
The current target allocation percentages for the major asset categories of the plan as of December 31, 2014 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced. | ||||||||||||||||||||||||||||||||||||||||||
TEP Plans | VEBA Trust | |||||||||||||||||||||||||||||||||||||||||
Fixed Income | 41 | % | 38 | % | ||||||||||||||||||||||||||||||||||||||
United States Large Cap | 24 | % | 39 | % | ||||||||||||||||||||||||||||||||||||||
Non-United States Developed | 15 | % | 7 | % | ||||||||||||||||||||||||||||||||||||||
Real Estate | 8 | % | — | % | ||||||||||||||||||||||||||||||||||||||
United States Small Cap | 5 | % | 5 | % | ||||||||||||||||||||||||||||||||||||||
Non-United States Emerging | 5 | % | 9 | % | ||||||||||||||||||||||||||||||||||||||
Private Equity | 2 | % | — | % | ||||||||||||||||||||||||||||||||||||||
Cash/Treasury Bills | — | % | 2 | % | ||||||||||||||||||||||||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||||||||||||||||||||||||
Pension Fund Descriptions | ||||||||||||||||||||||||||||||||||||||||||
For each type of asset category selected by the Pension Committee, our investment consultant assembles a group of third-party fund managers and allocates a portion of the total investment to each fund manager. In the case of the private equity fund, our investment consultant directs investments to a private equity manager that invests in third-parties’ funds. | ||||||||||||||||||||||||||||||||||||||||||
Other Retiree Benefit Assets | ||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2014, the fair value of VEBA trust assets was $12 million, of which $4 million were fixed income investments and $8 million were equities. As of December 31, 2013, the fair value of VEBA trust assets was $10 million, of which $4 million were fixed income investments and $6 million were equities. The VEBA trust assets are primarily Level 2. There are no Level 3 assets in the VEBA trust. | ||||||||||||||||||||||||||||||||||||||||||
ESTIMATED FUTURE BENEFIT PAYMENTS | ||||||||||||||||||||||||||||||||||||||||||
TEP expects the following benefit payments to be made by the defined benefit pension plans and other retiree benefit plan, which reflect future service, as appropriate. | ||||||||||||||||||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | 2020-2024 | |||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | $ | 17 | $ | 17 | $ | 19 | $ | 20 | $ | 21 | $ | 121 | ||||||||||||||||||||||||||||||
Other Retiree Benefits | 5 | 5 | 5 | 5 | 6 | 33 | ||||||||||||||||||||||||||||||||||||
One of TEP’s noncontributory defined benefit pension plans was amended in 2012 to allow terminated participants to elect early retirement benefits equal to the actuarial equivalent of the participant’s termination retirement benefit. The impact of the amendment on estimated future benefit payments was approximately $5 million in total, and the effect on the pension benefit obligation was less than $1 million. | ||||||||||||||||||||||||||||||||||||||||||
DEFINED CONTRIBUTION PLAN | ||||||||||||||||||||||||||||||||||||||||||
We offer a defined contribution savings plan to all eligible employees. The Internal Revenue Code identifies the plan as a qualified 401(k) plan. Participants direct the investment of contributions to certain funds in their account. We match part of a participant’s contributions to the plan. TEP made matching contributions to the plan of $5 million in each of 2014, 2013, and 2012. | ||||||||||||||||||||||||||||||||||||||||||
FAIR_VALUE_MEASUREMENTS_AND_DE
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS | FAIR VALUE MEASUREMENTS AND 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. | We categorize our financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. | |||||||||||||||||||||||||||||||||||||||||||||||||
FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||||||||||||||||||||||
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 | Net Amount | |||||||||||||||||||||||||||||||||||||||||||||
Netting of | ||||||||||||||||||||||||||||||||||||||||||||||||||
Total | Level 1 | Level 2 | Level 3 | Counterparty Netting of | Net | Energy | ||||||||||||||||||||||||||||||||||||||||||||
Energy Contracts Not | Amount | Contracts Not | ||||||||||||||||||||||||||||||||||||||||||||||||
Offset on the Balance | Offset on the | |||||||||||||||||||||||||||||||||||||||||||||||||
Sheets(5) | Balance | |||||||||||||||||||||||||||||||||||||||||||||||||
31-Mar-15 | Sheets(5) | |||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | December 31, 2014 | |||||||||||||||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||||
Cash Equivalents(1) | $ | 50 | $ | 50 | $ | — | $ | — | $ | — | $ | 50 | Millions of Dollars | |||||||||||||||||||||||||||||||||||||
Restricted Cash(1) | 2 | 2 | — | — | — | 2 | Assets | |||||||||||||||||||||||||||||||||||||||||||
Rabbi Trust Investments(2) | 27 | — | 27 | — | — | 27 | Cash Equivalents(1) | $ | 15 | $ | 15 | $ | — | $ | — | $ | — | $ | 15 | |||||||||||||||||||||||||||||||
Energy Contracts—Regulatory Recovery(3) | 1 | — | — | 1 | (1 | ) | — | Restricted Cash(1) | 2 | 2 | — | — | — | 2 | ||||||||||||||||||||||||||||||||||||
Rabbi Trust Investments(2) | 26 | — | 26 | — | — | 26 | ||||||||||||||||||||||||||||||||||||||||||||
Total Assets | 80 | 52 | 27 | 1 | (1 | ) | 79 | Energy Contracts – Regulatory Recovery(3) | 1 | — | — | 1 | (1 | ) | — | |||||||||||||||||||||||||||||||||||
Energy Contracts – No Regulatory Recovery(3) | 1 | — | — | 1 | (1 | ) | — | |||||||||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||
Energy Contracts—Regulatory Recovery(3) | (25 | ) | — | (13 | ) | (12 | ) | 1 | (24 | ) | Total Assets | 45 | 17 | 26 | 2 | (2 | ) | 43 | ||||||||||||||||||||||||||||||||
Energy Contracts—Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | |||||||||||||||||||||||||||||||||||||||||
Interest Rate Swaps(4) | (4 | ) | — | (4 | ) | — | — | (4 | ) | Liabilities | ||||||||||||||||||||||||||||||||||||||||
Energy Contracts – Regulatory Recovery(3) | (18 | ) | — | (9 | ) | (9 | ) | 1 | (17 | ) | ||||||||||||||||||||||||||||||||||||||||
Total Liabilities | (30 | ) | — | (17 | ) | (13 | ) | 1 | (29 | ) | Energy Contracts – No Regulatory Recovery(3) | (1 | ) | — | — | (1 | ) | 1 | — | |||||||||||||||||||||||||||||||
Energy Contracts – Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | |||||||||||||||||||||||||||||||||||||||||
Net Total Assets (Liabilities) | $ | 50 | $ | 52 | $ | 10 | $ | (12 | ) | $ | — | $ | 50 | Interest Rate Swaps(4) | (5 | ) | — | (5 | ) | — | — | (5 | ) | |||||||||||||||||||||||||||
Total Liabilities | (25 | ) | — | (14 | ) | (11 | ) | 2 | (23 | ) | ||||||||||||||||||||||||||||||||||||||||
Net Total Assets (Liabilities) | $ | 20 | $ | 17 | $ | 12 | $ | (9 | ) | — | $ | 20 | ||||||||||||||||||||||||||||||||||||||
Total | Level 1 | Level 2 | Level 3 | Counterparty Netting of | Net | |||||||||||||||||||||||||||||||||||||||||||||
Energy Contracts Not | Amount | |||||||||||||||||||||||||||||||||||||||||||||||||
Offset on the Balance | ||||||||||||||||||||||||||||||||||||||||||||||||||
Sheets(5) | ||||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | Total | Level 1 | Level 2 | Level 3 | Counterparty | Net Amount | ||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | Netting of | |||||||||||||||||||||||||||||||||||||||||||||||||
Assets | Energy | |||||||||||||||||||||||||||||||||||||||||||||||||
Cash Equivalents(1) | $ | 15 | $ | 15 | $ | — | $ | — | $ | — | $ | 15 | Contracts Not | |||||||||||||||||||||||||||||||||||||
Restricted Cash(1) | 2 | 2 | — | — | — | 2 | Offset on the | |||||||||||||||||||||||||||||||||||||||||||
Rabbi Trust Investments(2) | 26 | — | 26 | — | — | 26 | Balance | |||||||||||||||||||||||||||||||||||||||||||
Energy Contracts—Regulatory Recovery(3) | 2 | — | — | 2 | (2 | ) | — | Sheets(5) | ||||||||||||||||||||||||||||||||||||||||||
December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Total Assets | 45 | 17 | 26 | 2 | (2 | ) | 43 | |||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||||
Liabilities | Assets | |||||||||||||||||||||||||||||||||||||||||||||||||
Energy Contracts—Regulatory Recovery(3) | (18 | ) | — | (9 | ) | (9 | ) | 1 | (17 | ) | Cash Equivalents(1) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||||||
Energy Contracts—No Regulatory Recovery(3) | (1 | ) | — | — | (1 | ) | 1 | — | Restricted Cash(1) | 2 | 2 | — | — | — | 2 | |||||||||||||||||||||||||||||||||||
Energy Contracts—Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | Rabbi Trust Investments(2) | 22 | — | 22 | — | — | 22 | ||||||||||||||||||||||||||||||||||
Interest Rate Swaps(4) | (5 | ) | — | (5 | ) | — | — | (5 | ) | Energy Contracts – No Regulatory Recovery(3) | 2 | — | 1 | 1 | (1 | ) | 1 | |||||||||||||||||||||||||||||||||
Total Liabilities | (25 | ) | — | (14 | ) | (11 | ) | 2 | (23 | ) | Total Assets | 26 | 2 | 23 | 1 | (1 | ) | 25 | ||||||||||||||||||||||||||||||||
Net Total Assets (Liabilities) | $ | 20 | $ | 17 | $ | 12 | $ | (9 | ) | $ | — | $ | 20 | 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 | ) | |||||||||||||||||||||||||||||||||||||||||
(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. | Total Liabilities | 10 | — | (7 | ) | (3 | ) | 1 | (9 | ) | |||||||||||||||||||||||||||||||||||||||
(3) | Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk, and, at December 31, 2014, a power sale option. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below. | |||||||||||||||||||||||||||||||||||||||||||||||||
(4) | An Interest Rate Swap valued using an income valuation approach, based on the 6-month London Interbank Offered Rate (LIBOR) is included in Derivative Instruments on the balance sheets. | Net Total Assets (Liabilities) | $ | 16 | $ | 2 | $ | 16 | $ | (2 | ) | — | $ | 16 | ||||||||||||||||||||||||||||||||||||
(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 | ||||||||||||||||||||||||||||||||||||||||||||||||||
-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. | |||||||||||||||||||||||||||||||||||||||||||||||||
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. | -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), forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk, and a power sale option (Level 3). These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below. | |||||||||||||||||||||||||||||||||||||||||||||||||
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. | -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. | |||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
DERIVATIVE INSTRUMENTS | ||||||||||||||||||||||||||||||||||||||||||||||||||
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 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 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
The December 31, 2014 valuation of our power sale option was a function of observable market variables, regional power and gas prices, as well as the ratio between the two, which represents the prevailing market heat rate. | ||||||||||||||||||||||||||||||||||||||||||||||||||
We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no transfers between levels in the periods presented. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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 purchase options. Beginning in the third quarter of 2013, the fair value of our power purchase options is based on contractually specified option premiums instead of the Black-Scholes-Merton option pricing model because the needed inputs are no longer available. Based on the change, we transferred the purchase power options out of Level 3 and in to Level 2 at the end of third quarter of 2013. The amount transferred was less than $0.5 million. We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no other transfers between levels in the periods presented. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||||||||||||||||||||||||||||||||
The valuation of our power sale option is a function of observable market variables, regional power and gas prices, as well as the ratio between the two, the prevailing market heat rate. | ||||||||||||||||||||||||||||||||||||||||||||||||||
We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. The interest rate swap agreement expires January 2020. The realized loss recorded to Capital Lease Interest Expense was less than $0.5 million for the three months ended March 31, 2015 and less than $1 million for the three months ended March 31, 2014. The realized loss recorded to Long-Term Debt Interest Expense for three months ended March 31, 2014 was less than $0.5 million. 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 are reported in the statements of other comprehensive income. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Energy Contracts—Regulatory Recovery | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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 table: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||||||||||||||||||||||||||||||||
We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. At December 31, 2014, we have one interest rate swap agreement which expires in 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 are reported in the statements of comprehensive income. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||
2015 | 2014 | Energy Contracts - Regulatory Recovery | ||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||||
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities | $ | (6 | ) | $ | 1 | 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: | ||||||||||||||||||||||||||||||||||||||||||||
Energy Contracts—No Regulatory Recovery | ||||||||||||||||||||||||||||||||||||||||||||||||||
Forward contracts with long-term wholesale customers do not qualify for regulatory recovery. For these contracts that qualify as derivatives, we record unrealized gains and losses in the income statement, unless and until a normal purchase or normal sale election is made. In the first quarter of 2015, TEP made a normal sale election for a three-year sales option contract entered into in December 2014. | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Volumes | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||||||||||||
Unrealized Net Gain (Loss) Recorded in Regulatory (Assets) Liabilities | $ | (18 | ) | $ | — | $ | 6 | |||||||||||||||||||||||||||||||||||||||||||
At March 31, 2015, we have energy contracts that will settle through the first quarter of 2018. The volumes associated with our energy contracts were as follows: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Realized gains and losses on settled contracts are fully recoverable through the PPFAC. | ||||||||||||||||||||||||||||||||||||||||||||||||||
March 31, 2015 | December 31, 2014 | |||||||||||||||||||||||||||||||||||||||||||||||||
Power Contracts GWh | 1,008 | 2,604 | Energy Contracts - No Regulatory Recovery | |||||||||||||||||||||||||||||||||||||||||||||||
Gas Contracts GBtu | 24,027 | 19,932 | ||||||||||||||||||||||||||||||||||||||||||||||||
From time to time, TEP may enter into forward contracts with long-term wholesale customers that qualify as derivatives. We record unrealized gains and losses on these energy derivatives in the income statement as they do not qualify for regulatory recovery. In December 2014, TEP entered into a three-year sales option contract. The unrealized gain recorded in Electric Wholesale Sales in 2014 was less than $1 million. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Level 3 Fair Value Measurements | ||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Volumes | ||||||||||||||||||||||||||||||||||||||||||||||||||
The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: | ||||||||||||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, we have energy contracts that will settle through the fourth quarter of 2017. The volumes associated with our energy contracts were as follows: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Valuation | Fair Value at | Range of | ||||||||||||||||||||||||||||||||||||||||||||||||
Approach | 31-Mar-15 | Unobservable | December 31, 2014 | December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||||||
Assets | Liabilities | Unobservable Inputs | Input | Power Contracts GWh | 2,604 | 779 | ||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | Gas Contracts GBtu | 19,932 | 9,615 | |||||||||||||||||||||||||||||||||||||||||||||||
Forward Power Contracts | Market approach | $ | 1 | $ | (8 | ) | Market price per MWh | $ | 23.8 | $ | 37.7 | |||||||||||||||||||||||||||||||||||||||
Level 3 Fair Value Measurements | ||||||||||||||||||||||||||||||||||||||||||||||||||
Gas Option Contracts | Option model | — | (5 | ) | Market price per MMbtu | $ | 2.34 | $ | 3.22 | |||||||||||||||||||||||||||||||||||||||||
The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Gas volatility | 24.15 | % | 39.91 | % | ||||||||||||||||||||||||||||||||||||||||||||||
Level 3 Energy Contracts | $ | 1 | $ | (13 | ) | |||||||||||||||||||||||||||||||||||||||||||||
Fair Value at | Range of | |||||||||||||||||||||||||||||||||||||||||||||||||
Valuation | Fair Value at | Range of | 31-Dec-14 | Unobservable Input | ||||||||||||||||||||||||||||||||||||||||||||||
Approach | December 31, 2014 | Unobservable | Valulation Approach | Assets | Liabilities | Unobservable Inputs | Minimum | Maximum | ||||||||||||||||||||||||||||||||||||||||||
Assets | Liabilities | Unobservable Inputs | Input | |||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | Forward Power Contracts | Market approach | $ | 1 | $ | (6 | ) | Market price per MWh | $22.35 | $39.05 | ||||||||||||||||||||||||||||||||||||||||
Forward Power Contracts | Market approach | $ | 1 | $ | (6 | ) | Market price per MWh | $ | 22.35 | $ | 39.05 | |||||||||||||||||||||||||||||||||||||||
Power Sale Option | Market approach | 1 | (1 | ) | Market price per MWh | $27.75 | $44.94 | |||||||||||||||||||||||||||||||||||||||||||
Power Sale Option | Market approach | 1 | (1 | ) | Market price per MWh | $ | 27.75 | $ | 44.94 | |||||||||||||||||||||||||||||||||||||||||
Market price per MMbtu | $ | 2.88 | $ | 4.02 | Market price per MWh | $2.88 | $4.02 | |||||||||||||||||||||||||||||||||||||||||||
Gas Option Contracts | Option model | — | (4 | ) | Market price per MMbtu | $ | 2.72 | $ | 3.26 | Gas Option Contracts | Option model | — | (4 | ) | Market price per MWh | $2.72 | $3.26 | |||||||||||||||||||||||||||||||||
Gas volatility | 30.8 | % | 53.29 | % | ||||||||||||||||||||||||||||||||||||||||||||||
Gas volatility | 30.80% | 53.29% | ||||||||||||||||||||||||||||||||||||||||||||||||
Level 3 Energy Contracts | $ | 2 | $ | (11 | ) | Level 3 Energy Contracts | $ | 2 | $ | (11 | ) | |||||||||||||||||||||||||||||||||||||||
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, that 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value at | Range of | |||||||||||||||||||||||||||||||||||||||||||||||||
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: | 31-Dec-13 | Unobservable Input | ||||||||||||||||||||||||||||||||||||||||||||||||
Valulation Approach | Assets | Liabilities | Unobservable Inputs | Minimum | Maximum | |||||||||||||||||||||||||||||||||||||||||||||
Forward Power Contracts | Market approach | $ | — | $ | (3 | ) | Market price per MWh | $27.00 | $48.25 | |||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||
2015 | 2014 | Gas Option Contracts | Option model | 1 | — | Market price per MWh | $3.88 | $4.32 | ||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||||
Balances at December 31 | $ | (9 | ) | $ | (2 | ) | Gas volatility | 25.05% | 35.07% | |||||||||||||||||||||||||||||||||||||||||
Realized/Unrealized Gains/(Losses) Recorded to: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Net Regulatory Assets/Liabilities—Derivative Instruments | (2 | ) | (1 | ) | Level 3 Energy Contracts | $ | 1 | $ | (3 | ) | ||||||||||||||||||||||||||||||||||||||||
Settlements | (1 | ) | 1 | |||||||||||||||||||||||||||||||||||||||||||||||
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. Generally, 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, rather than in the income statement. | ||||||||||||||||||||||||||||||||||||||||||||||||||
Balances at March 31 | $ | (12 | ) | $ | (2 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period | $ | (3 | ) | $ | — | |||||||||||||||||||||||||||||||||||||||||||||
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: | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||||||||||
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; 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. | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||||||||||||
Balances at Beginning of Year | $ | (2 | ) | $ | — | |||||||||||||||||||||||||||||||||||||||||||||
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. | Realized/Unrealized/(Losses) Recorded to: | |||||||||||||||||||||||||||||||||||||||||||||||||
Net Regulatory Assets/Liabilities – Derivative Instruments | (8 | ) | (2 | ) | ||||||||||||||||||||||||||||||||||||||||||||||
Settlements | 1 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Material adverse changes could trigger credit risk-related contingent features. At March 31, 2015, 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 $27 million, compared with $21 million at December 31, 2014. At March 31, 2015, TEP had no cash collateral posted and less than $0.5 million of LOCs as credit enhancements with its counterparties and held no collateral from its counterparties. The additional collateral to be posted if credit-risk contingent features were triggered would be $27 million. | Balances at End of Year | $ | (9 | ) | $ | (2 | ) | |||||||||||||||||||||||||||||||||||||||||||
FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE | Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period | $ | (8 | ) | $ | (1 | ) | |||||||||||||||||||||||||||||||||||||||||||
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: | ||||||||||||||||||||||||||||||||||||||||||||||||||
CREDIT RISK | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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; 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. | ||||||||||||||||||||||||||||||||||||||||||||||||||
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: | ||||||||||||||||||||||||||||||||||||||||||||||||||
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 December 31, 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 $21 million, compared with $5 million at December 31, 2013. At December 31, 2014, TEP had no cash collateral posted and less than $1 million of LOCs as credit enhancements with its counterparties and held no collateral from its counterparties. The additional collateral to be posted if credit-risk contingent features were triggered would be $21 million. | ||||||||||||||||||||||||||||||||||||||||||||||||||
March 31, 2015 | December 31, 2014 | |||||||||||||||||||||||||||||||||||||||||||||||||
Fair | Carrying | Fair | Carrying | Fair | FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE | |||||||||||||||||||||||||||||||||||||||||||||
ValueHierarchy | Value | Value | Value | Value | ||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | 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: | |||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt | Level 2 | $ | 1,541 | $ | 1,642 | $ | 1,372 | $ | 1,457 | |||||||||||||||||||||||||||||||||||||||||
• | 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 estimated the price at which an investor would realize a target internal rate of return. Our estimates included: 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 assumed 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. The balance was transferred to Plant in Service upon the December 2014 purchase of an additional undivided interest in Springerville Unit 1. See Note 3 of Notes to Consolidated Financial Statements. | |||||||||||||||||||||||||||||||||||||||||||||||||
• | 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: | ||||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | December 31, 2013 | |||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value | Carrying | Fair Value | Carrying | Fair Value | ||||||||||||||||||||||||||||||||||||||||||||||
Hierachy | Value | Value | ||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Investment in Lease Equity(1) | Level 3 | N/A | N/A | $ | 36 | $ | $25 | |||||||||||||||||||||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt | Level 2 | 1,372 | 1,457 | 1,223 | 1,214 | |||||||||||||||||||||||||||||||||||||||||||||
-1 | Balance was transferred to Plant in Service in December 2014. |
RECENTLY_ISSUED_ACCOUNTING_PRO
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS | 3 Months Ended | 12 Months Ended |
Mar. 31, 2015 | Dec. 31, 2014 | |
Accounting Changes and Error Corrections [Abstract] | ||
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS | RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS | RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS |
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. The revenue standard requires entities to apply the guidance retrospectively or recognize the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings supplemented by additional disclosures. On April 1, 2015, the FASB proposed to defer the effective date of the revenue recognition standard by one year. Based on the proposed effective date, we will be required to adopt the new guidance for annual and interim periods beginning January 1, 2018; early adoption is permitted for annual and interim periods beginning January 1, 2017. We are in the process of identifying contracts with customers and performance obligations in contracts. | 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 June 2014, the FASB issued guidance that requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. An entity can elect to adopt the amendment prospectively or retrospectively. TEP does not expect the adoption of this guidance to have a material impact on our disclosures, financial condition, results of operations, or cash flows. | 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. | 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. | |
In January 2015, the FASB issued an accounting standards update that removes the concept of extraordinary items from U.S. GAAP. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. TEP does not expect the adoption of this guidance to impact its results of operations or disclosures. | ||
In February 2015, the FASB issued guidance that amends the current consolidation guidance; the amendment affects both the variable interest entity and voting interest entity consolidation models. This standard is effective beginning January 1, 2016; early adoption is permitted. We are evaluating the impact to our financial statements and disclosures. | ||
In April 2015, the FASB issued guidance which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, rather than as deferred charges. The amendment is effective for periods beginning January 1, 2016 and will be applied retrospectively; early adoption is permitted. The adoption of this standard is expected to result in reclassification of debt issuance costs from Other Current Assets and Other Assets to Long-Term Debt on our balance sheet. TEP’s deferred debt issuance costs associated with long-term debt outstanding totaled $12 million at March 31, 2015 and $11 million at December 31, 2014, of which approximately $1 million is classified as current at each date. | ||
In April 2015, the FASB issued guidance that will help entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement either as a software license or a service contract. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. An entity can elect to adopt the amendment prospectively or retrospectively. TEP does not expect the adoption of this guidance to have a material impact on our disclosures, financial condition, results of operations, or cash flows. |
NATURE_OF_OPERATIONS_AND_FINAN1
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Accounting Policies [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. 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 | |||||||||||||
UNS Energy, the parent of TEP, was acquired by Fortis for $60.25 per share of UNS Energy common stock in cash effective August 15, 2014. | |||||||||||||
The Arizona Corporation Commission’s (ACC) approval was subject to certain stipulations, including, but not limited to, the following: | |||||||||||||
• | TEP will provide credits on retail customers’ bills totaling approximately $19 million over five years: $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; | ||||||||||||
• | Dividends paid from TEP to UNS Energy cannot exceed 60 percent of TEP’s annual net income for the earlier of five years or until such time that TEP’s equity capitalization reaches 50 percent of total capital; and | ||||||||||||
• | Fortis making an equity investment of at least $220 million to UNS Energy and its regulated subsidiaries, including TEP. Fortis exceeded the investment requirement by contributing $287 million to UNS Energy through December 31, 2014. UNS Energy then contributed $225 million 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, reported in Operations and Maintenance and Other Expense, include investment banker fees, legal expenses, and accelerated expenses for certain share-based compensation awards. | |||||||||||||
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 2014 due to the accelerated vesting of the awards. TEP recorded total share- based compensation expense of $5 million for the year ended December 31, 2014, $3 million for the year ended December 31, 2013, and $2 million for the year ended December 31, 2012. In August 2014, UNS Energy settled all outstanding share-based compensation awards in cash. | |||||||||||||
BASIS OF PRESENTATION | |||||||||||||
TEP’s consolidated financial statements and disclosures are presented in accordance with generally accepted accounting principles (GAAP) in the United States which includes specific accounting guidance for regulated operations. See Note 2 of Notes to Consolidated Financial Statements. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stations and transmission facilities with non-affiliated entities. TEP’s proportionate share of jointly owned facilities is recorded as Utility Plant on the consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the consolidated statements of income. See Note 3 of Notes to Consolidated Financial Statements. | |||||||||||||
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 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 BALANCE SHEET AND STATEMENT OF CAPITALIZATION AS OF DECEMBER 31, 2013 | |||||||||||||
TEP revised its December 31, 2013 balance sheet and statement of capitalization to correct an immaterial 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. The notes that follow have been updated for this revision. | |||||||||||||
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. | ||||||||||||
USE OF ACCOUNTING ESTIMATES | |||||||||||||
Management uses estimates and assumptions when preparing financial statements under GAAP. These estimates and assumptions affect: | |||||||||||||
• | Assets and liabilities on our balance sheets at the dates of the financial statements; | ||||||||||||
• | Our disclosures about contingent assets and liabilities at the dates of the financial statements; and | ||||||||||||
• | Our revenues and expenses in our income statements during the periods presented. | ||||||||||||
Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual results may differ from the estimates. | |||||||||||||
ACCOUNTING FOR REGULATED OPERATIONS | |||||||||||||
We apply accounting standards that recognize the economic effects of rate regulation. As a result, we capitalize certain costs that would be recorded as expense or in Accumulated Other Comprehensive Income (AOCI) by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in the rates charged to retail customers or to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are expected to be returned to customers through future rate reductions. | |||||||||||||
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. We evaluate regulatory assets each period and believe recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 of Notes to Consolidated Financial Statements. | |||||||||||||
TEP applies regulatory accounting as the following conditions exist: | |||||||||||||
• | An independent regulator sets rates; | ||||||||||||
• | The regulator sets the rates to recover the specific enterprise’s costs of providing service; and | ||||||||||||
• | Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers. | ||||||||||||
CASH AND CASH EQUIVALENTS | |||||||||||||
We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents. | |||||||||||||
RESTRICTED CASH | |||||||||||||
Cash balances that are restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property—Other on the balance sheets. Restricted cash was $2 million at December 31, 2014 and December 31, 2013. | |||||||||||||
UTILITY PLANT | |||||||||||||
Utility Plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. We report utility plant at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction (AFUDC), less contributions in aid of construction. | |||||||||||||
We record the cost of repairs and maintenance, including planned major overhauls, to Operations and Maintenance (O&M) expense in the income statement as costs are incurred. | |||||||||||||
When a unit of regulated property is retired, we reduce accumulated depreciation by the original cost plus removal costs less any salvage value. There is no income statement impact. | |||||||||||||
AFUDC and Capitalized Interest | |||||||||||||
AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense in the income statement. The capitalized cost for equity funds is recorded as Other Income in the income statement. | |||||||||||||
The average AFUDC rates on regulated construction expenditures are included in the table below: | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Average AFUDC Rates | 7.3 | % | 7.38 | % | 7.22 | % | |||||||
Depreciation | |||||||||||||
We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 2 and Note 3 of Notes to Consolidated Financial Statements. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. Below are the summarized average annual depreciation rates for all utility plant: | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Average Annual Depreciation Rates | 2.99 | % | 3.16 | % | 3.22 | % | |||||||
Utility Plant Under Capital Leases | |||||||||||||
TEP financed the following generation assets with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 3 of Notes to Consolidated Financial Statements) and Interest Expense—Capital Leases. The lease terms are described in Note 5 of Notes to Consolidated Financial Statements. | |||||||||||||
Computer Software Costs | |||||||||||||
We capitalize costs incurred to purchase and develop internal use computer software and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense. | |||||||||||||
INVESTMENTS IN LEASE EQUITY | |||||||||||||
Prior to December 2014, TEP held a 14.1% equity interest in Springerville Unit 1 and a 7% interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 10 of Notes to Consolidated Financial Statements. | |||||||||||||
TEP accounted for its equity interest in the Springerville Unit 1 Lease trust using the equity method. In December 2014, following the purchase of an additional undivided interest in Springerville Unit 1, TEP transferred the balance of its investment in lease equity to Plant in Service. | |||||||||||||
ASSET RETIREMENT OBLIGATIONS | |||||||||||||
TEP has identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its photovoltaic assets as a result of entering into various ground leases. We record a liability for a legal ARO in the period in which it is incurred if it can be reasonably estimated. When a new obligation is recorded, we capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. We record the increase in the liability due to the passage of time by recognizing accretion expense in O&M expense and depreciate the capitalized cost over the useful life of the related asset or when applicable, the terms of the lease subject to ARO requirements. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs. | |||||||||||||
Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. We recover those amounts in the rates charged to retail customers and have recorded an obligation for estimated costs of removal as regulatory liabilities. | |||||||||||||
EVALUATION OF ASSETS FOR IMPAIRMENT | |||||||||||||
We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates. | |||||||||||||
DEFERRED FINANCING COSTS | |||||||||||||
We defer the costs to issue debt and amortize such costs to interest expense on a straight-line basis over the life of the debt as this approximates the effective interest method. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. | |||||||||||||
We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt. | |||||||||||||
OPERATING REVENUES | |||||||||||||
We recognize revenues related to the sale of energy when services or commodities are delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates. | |||||||||||||
For purchased power and wholesale sales contracts that are settled financially, TEP nets the sales contracts with the purchase power contracts and reflects the net amount as Electric Wholesale Sales. | |||||||||||||
TEP recognizes monthly management fees in Other Revenues as the operator of 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 Agriculture Improvement and Power District (SRP). Additionally, Other Revenues include reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities. The offsetting expenses are recorded in the respective line items of the income statements based on the nature of services provided. As the operating agent for Tri-State and SRP, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues in the period earned. | |||||||||||||
The ACC has authorized mechanisms for Lost Fixed Cost Recovery (LFCR) related to kWh sales lost due to Energy Efficiency (EE) Standards and Distributed Generation (DG). We recognize revenues in the period that verifiable energy savings occur. Revenue recognition related to the LFCR creates a regulatory asset until such time as the revenue is collected. | |||||||||||||
ALLOWANCE FOR DOUBTFUL ACCOUNTS | |||||||||||||
We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. | |||||||||||||
INVENTORY | |||||||||||||
We value materials, supplies and fuel inventory at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost (even if in excess of market) will be recovered in retail rates. We capitalize handling and procurement costs (such as labor, overhead costs, and transportation costs) as part of the cost of the inventory. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials. | |||||||||||||
PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE | |||||||||||||
We recover actual fuel, purchased power and transmission costs to provide electric service to retail customers through base fuel rates and a Purchased Power and Fuel Adjustment Clause (PPFAC); the ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 2 of Notes to Consolidated Financial Statements. | |||||||||||||
RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS | |||||||||||||
The ACC’s Renewable Energy Standard (RES) requires TEP to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements in 2025, with distributed generation accounting for 30% of the annual renewable energy requirement. TEP must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out this plan is recovered from retail customers through the RES surcharge. The ACC has also approved recovery of operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through the RES tariff until such costs are reflected in retail customer rates. | |||||||||||||
TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC’s EE Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs. The Electric EE Standards require increasing annual targeted retail Kilowatt-hours (kWh) savings equal to 22% by 2020. | |||||||||||||
Any RES or DSM surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in the financial statements as a regulatory asset or liability. TEP recognizes RES and DSM surcharge revenue in Electric Retail Sales in amounts necessary to offset recognized qualifying expenditures. | |||||||||||||
RENEWABLE ENERGY CREDITS | |||||||||||||
The ACC measures compliance with the RES requirements through Renewable Energy Credits (RECs). A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC. | |||||||||||||
When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes Purchased Power expense and Other Revenues in an equal amount. See Note 2 of Notes to Consolidated Financial Statements. | |||||||||||||
INCOME TAXES | |||||||||||||
Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We reduce deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized. | |||||||||||||
Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense. | |||||||||||||
Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets – Noncurrent includes income taxes recoverable through future rates, which reflects the future revenues due to TEP from ratepayers as these tax benefits reverse. See Note 2 of Notes to Consolidated Financial Statements. | |||||||||||||
We account for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as Regulatory Liabilities – Noncurrent and amortized as a reduction in Income Tax Expense over the tax life of the underlying asset. Income Tax Expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as regulatory assets effective July 1, 2013 due to the 2013 TEP Rate Order. All other federal and state income tax credits are treated as a reduction to Income Tax Expense in the year the credit arises. | |||||||||||||
Income tax liabilities are allocated to TEP based on its taxable income as reported in the FortisUS Inc. consolidated tax return. | |||||||||||||
TAXES OTHER THAN INCOME TAXES | |||||||||||||
We act as conduits or collection agents for sales taxes, utility taxes, franchise fees, and regulatory assessments. As we bill customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable to governmental agencies on the balance sheet for these taxes and assessments. These amounts are not reflected in the income statements. | |||||||||||||
DERIVATIVE INSTRUMENTS | |||||||||||||
We use various physical and financial derivative instruments, including forward contracts, financial swaps and call and put options, to meet forecasted load and reserve requirements, to reduce our exposure to energy commodity price volatility and to hedge our interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the consolidated balance sheets and measure those instruments at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. | |||||||||||||
Cash Flow Hedges | |||||||||||||
TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements for the Springerville Common Lease and variable rate industrial development revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that does not qualify for regulatory recovery using a six-year power purchase swap agreement. TEP accounts for cash flow hedges as follows: | |||||||||||||
• | The effective portion of the change in the fair value is recorded in AOCI and the ineffective portion, if any, is recognized in earnings; and | ||||||||||||
• | When TEP determines a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP recognizes the change in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs. | ||||||||||||
We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items. | |||||||||||||
Energy Contracts—Regulatory Recovery | |||||||||||||
TEP is authorized to recover the costs of hedging activities entered into to mitigate energy price risk for retail customers. We record unrealized gains and losses on these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC mechanism. | |||||||||||||
Energy Contracts—No Regulatory Recovery | |||||||||||||
From time to time, TEP may enter into forward contracts with long-term wholesale customers that qualify as derivatives. We record unrealized gains and losses on these energy derivatives in the income statement as they do not qualify for regulatory recovery. | |||||||||||||
Master Netting Agreements | |||||||||||||
We have elected gross presentation for our derivative contracts under master netting agreements and collateral positions. We separate all derivatives into current and long-term portions on the balance sheet. | |||||||||||||
Normal Purchases and Normal Sales | |||||||||||||
We enter into forward energy purchase and sales contracts, including options, with counterparties that have generating capacity to support our current load forecasts or counterparties that have load serving requirements. We have elected the normal purchase or normal sales exception for these contracts which are not required to be measured at fair value and are accounted for on an accrual basis. | |||||||||||||
Commodity Trading | |||||||||||||
We did not engage in trading of derivative financial instruments for the periods presented. | |||||||||||||
PENSION AND OTHER RETIREE BENEFITS | |||||||||||||
We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We also provide limited health care and life insurance benefits for retirees. | |||||||||||||
We recognize the underfunded status of our defined benefit pension plans as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers and expect to recover these costs over the estimated service lives of employees. | |||||||||||||
Additionally, we maintain a Supplemental Executive Retirement Plan (SERP) for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI. | |||||||||||||
Pension and other retiree benefit expenses are determined by actuarial valuations based on assumptions that we evaluate annually. See Note 8 of Notes to Consolidated Financial Statements. |
UTILITY_PLANT_AND_JOINTLYOWNED
UTILITY PLANT AND JOINTLY-OWNED FACILITIES | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Text Block [Abstract] | |||||||||||||||||||
UTILITY PLANT AND JOINTLY-OWNED FACILITIES | UTILITY PLANT AND JOINTLY-OWNED FACILITIES | ||||||||||||||||||
UTILITY PLANT | |||||||||||||||||||
The following table shows Utility Plant in Service by major class: | |||||||||||||||||||
December 31, | |||||||||||||||||||
2014 | 2013 | ||||||||||||||||||
Millions of Dollars | |||||||||||||||||||
Plant in Service: | |||||||||||||||||||
Electric Generation Plant | $ | 2,388 | $ | 1,889 | |||||||||||||||
Electric Transmission Plant | 898 | 825 | |||||||||||||||||
Electric Distribution Plant | 1,398 | 1,298 | |||||||||||||||||
General Plant | 338 | 312 | |||||||||||||||||
Intangible Plant - Software Costs(1) (2) | 149 | 141 | |||||||||||||||||
Electric Plant Held for Future Use | 4 | 3 | |||||||||||||||||
Total Plant in Service | $ | 5,175 | $ | 4,468 | |||||||||||||||
Utility Plant under Capital Leases(3) | $ | 667 | $ | 638 | |||||||||||||||
-1 | Unamortized computer software costs were $31 million as of December 31, 2014, and $39 million as of December 31, 2013. | ||||||||||||||||||
-2 | The amortization of computer software costs was $17 million in 2014, $14 million in 2013, and $13 million in 2012. | ||||||||||||||||||
-3 | In 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5 of Notes to Consolidated Financial Statements. | ||||||||||||||||||
Utility Plant under Capital Leases | |||||||||||||||||||
All utility plant under capital leases is used in generation operations and amortized over the primary lease term. See Note 5 of Notes to Consolidated Financial Statements. At December 31, 2014, the utility plant under capital leases includes: 1) Springerville Unit 1; 2) Springerville Common Facilities; and 3) Springerville Coal Handling Facilities. The following table shows the amount of lease expense incurred for generation-related capital leases: | |||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||
Millions of Dollars | |||||||||||||||||||
Lease Expense: | |||||||||||||||||||
Interest Expense – Included in: | |||||||||||||||||||
Capital Leases | $ | 10 | $ | 25 | $ | 34 | |||||||||||||
Operating Expenses – Fuel | 1 | 2 | 3 | ||||||||||||||||
Amortization of Capital Lease Assets – Included in: | |||||||||||||||||||
Operating Expenses – Fuel | 6 | 5 | 4 | ||||||||||||||||
Operating Expenses – Amortization | 16 | 15 | 14 | ||||||||||||||||
Total Lease Expense: | $ | 33 | $ | 47 | $ | 55 | |||||||||||||
Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available at December 31, 2014, were as follows: | |||||||||||||||||||
December 31, 2014 | |||||||||||||||||||
Annual Depreciation | Average Remaining Life | ||||||||||||||||||
Rate (3) | in Years | ||||||||||||||||||
Major Class of Utility Plant in Service: | |||||||||||||||||||
Electric Generation Plant(1) | 3.31% | 22 | |||||||||||||||||
Electric Transmission Plant | 1.48% | 32 | |||||||||||||||||
Electric Distribution Plant(1) | 2.08% | 35 | |||||||||||||||||
General Plant(1) | 5.48% | 11 | |||||||||||||||||
Intangible Plant(2) | Various | Various | |||||||||||||||||
-1 | In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 2 of Notes to Consolidated Financial Statements. | ||||||||||||||||||
-2 | The majority of TEP’s investment in intangible plant represents computer software, which is being amortized over its expected useful life of three to five years for smaller application software. For large enterprise software, we use the remaining life depreciation method. At December 31, 2014, remaining lives ranged from one to six years. | ||||||||||||||||||
-3 | The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant. | ||||||||||||||||||
JOINTLY-OWNED FACILITIES | |||||||||||||||||||
At December 31, 2014, TEP was a participant in jointly-owned generating stations and transmission systems as follows: | |||||||||||||||||||
Ownership | Plaint in Service | Construction | Accumulated | Net Book | |||||||||||||||
Percentage | Work in | Depreciation | Value | ||||||||||||||||
Progress | |||||||||||||||||||
Millions of Dollars | |||||||||||||||||||
San Juan Units 1 and 2 | 50.00% | $ | 453 | $ | 8 | $ | 242 | $ | 219 | ||||||||||
Navajo Units 1, 2, and 3 | 7.50% | 153 | 1 | 112 | 42 | ||||||||||||||
Four Corners Units 4 and 5 | 7.00% | 104 | 3 | 77 | 30 | ||||||||||||||
Luna Energy Facility | 33.30% | 55 | — | 2 | 53 | ||||||||||||||
Gila River Unit 3 | 75.00% | 186 | — | 54 | 132 | ||||||||||||||
Gila River Common Facilities | 18.75% | 42 | — | 11 | 31 | ||||||||||||||
Transmission Facilities | Various | 371 | 21 | 193 | 199 | ||||||||||||||
Total | $ | 1,364 | $ | 33 | $ | 691 | $ | 706 | |||||||||||
In December 2014, TEP completed the purchase of Gila River Unit 3. TEP jointly owns Gila River Unit 3 with UNS Electric, Inc., an affiliated subsidiary of UNS Energy (UNS Electric). See Note 7 of Notes to Consolidated Financial Statements. | |||||||||||||||||||
TEP is responsible for its share of operating and capital costs for the above facilities. TEP accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation. | |||||||||||||||||||
Springerville Unit 1 | |||||||||||||||||||
At December 31, 2014, TEP owned 24.7% of Springerville Unit 1 and continued to lease the remaining portion of the facility. Effective January 1, 2015, following completion of the purchase of an additional 24.8% leased interest in Springerville Unit 1 and expiration of the lease, TEP has a 49.5% ownership interest in the Springerville Unit 1 generating station and will operate the facility on behalf of third parties, i.e. Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of the remaining two owner participants, Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners). The Third-Party Owners are responsible for their share of operating and capital costs for the facility. See Note 6 of Notes to Consolidated Financial Statements. | |||||||||||||||||||
ASSET RETIREMENT OBLIGATIONS | |||||||||||||||||||
The accrual of AROs is primarily related to generation and photovoltaic assets and is included in Deferred Credits and Other Liabilities on the balance sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets: | |||||||||||||||||||
December 31, | |||||||||||||||||||
2014 | 2013 | ||||||||||||||||||
Millions of Dollars | |||||||||||||||||||
Beginning Balance | $ | 22 | $ | 14 | |||||||||||||||
Liabilities Incurred | 5 | — | |||||||||||||||||
Accretion Expense or Regulatory Deferral | 1 | 1 | |||||||||||||||||
Revisions to the Present Value of Estimated Cash Flows(1) | — | 7 | |||||||||||||||||
Ending Balance | $ | 28 | $ | 22 | |||||||||||||||
-1 | Primarily related to changes in expected retirement dates of generating facilities. |
PURCHASE_OF_GASFIRED_GENERATIO
PURCHASE OF GAS-FIRED GENERATION FACILITY | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Commitments and Contingencies Disclosure [Abstract] | |||||
PURCHASE OF GAS-FIRED GENERATION FACILITY | PURCHASE OF GAS-FIRED GENERATION FACILITY | ||||
On December 10, 2014, TEP and UNS Electric acquired Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW located in Gila Bend, Arizona, from a subsidiary of Entegra Power Group LLC. TEP purchased a 75% undivided interest in Gila River Unit 3 (413 MW) for $164 million, and UNS Electric purchased the remaining 25% undivided interest. Upon the closing of the transaction, the letter of credit TEP provided in June 2014 for $15 million was canceled. | |||||
TEP’s purchase of Gila River Unit 3 is intended to replace the reduction of 195 MW of output from Springerville Unit 1 and the 170 MW of capacity expected to be retired at San Juan in 2017. | |||||
The transaction has been accounted for using the acquisition method of accounting which requires that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the assets acquired and liabilities assumed as of the acquisition date: | |||||
Millions of Dollars | |||||
Utility Plant - Net | $ | 163 | |||
Materials and Supplies | 2 | ||||
ARO Obligation Assumed(1) | (1 | ) | |||
Total Purchase Price | $ | 164 | |||
-1 | The ARO obligation was recorded at net present value in Deferred Credits and Other Liabilities - Other on TEP’s balance sheet. |
SUPPLEMENTAL_CASH_FLOW_INFORMA
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Supplemental Cash Flow Elements [Abstract] | |||||||||||||
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION | ||||||||||||
CASH PAYMENTS | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Thousands of Dollars | |||||||||||||
Interest Paid, Net of Amounts Capitalized | $ | (82,653 | ) | $ | (52,589 | ) | $ | (52,125 | ) | ||||
Income Taxes Paid | — | — | (1,796 | ) | |||||||||
NON-CASH TRANSACTIONS | |||||||||||||
In 2014, the following non-cash transactions occurred: | |||||||||||||
• | 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 5 of Notes to Consolidated Financial Statements. | ||||||||||||
• | In 2013, the following non-cash transactions occurred: | ||||||||||||
• | TEP recorded an increase of $55 million to both Utility Plant Under Capital Leases and Capital Lease Obligations due to TEP’s commitment to purchase leased interests in December 2014 and January 2015. | ||||||||||||
• | In March 2013, the Industrial Development Authority of Pima County, Arizona issued approximately $91 million aggregate principal amount of unsecured tax-exempt Industrial Development Revenue Bonds (IDRBs) for the benefit of TEP. The proceeds were used 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. | ||||||||||||
• | In November 2013, the Industrial Development Authority of Apache County, Arizona issued $100 million of tax-exempt, variable rate IDRBs for the benefit of TEP. The proceeds were deposited with the trustee to redeem debt in December 2013. TEP had no cash receipts or payments as a result of this transaction. See Note 5 of Notes to Consolidated Financial Statements. | ||||||||||||
In 2012, the following non-cash transactions occurred: | |||||||||||||
• | In June 2012, the Industrial Development Authority of Pima County, Arizona issued approximately $16 million of unsecured tax-exempt IDBs. In March 2012, the Industrial Development Authority of Apache County, Arizona issued $177 million of unsecured tax-exempt pollution control bonds. In 2012, TEP redeemed the $193 million of tax-exempt bonds and reissued debt using a trustee. Since the cash flowed through trust accounts, the redemption and reissuance of debt resulted in a non-cash transaction at TEP. | ||||||||||||
Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows: | |||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Thousands of Dollars | |||||||||||||
(Decrease)/Increase to Utility Plant Accruals(1) | $ | 5,138 | $ | 4,995 | $ | 4,813 | |||||||
Net Cost of Removal of Interim Retirements(2) | 12,128 | 25,182 | 35,983 | ||||||||||
Capital Lease Obligations(3) | 1,107 | 9,039 | 11,967 | ||||||||||
Asset Retirement Obligations(4) | 4,117 | 8,064 | 789 | ||||||||||
(1) | The non-cash additions to Utility Plant represent accruals for capital expenditures. | ||||||||||||
(2) | The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings. | ||||||||||||
(3) | The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments. | ||||||||||||
(4) | The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations. |
INCOME_TAXES
INCOME TAXES | 12 Months Ended | ||||||||||||
Dec. 31, 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: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Millions of Dollars | |||||||||||||
Federal Income Tax Expenses at Statutory Rate | $ | 56 | $ | 52 | $ | 37 | |||||||
State Income Tax Espense, Net of Federal Deduction | 7 | 7 | 5 | ||||||||||
Federal/State Tax Credits | (5 | ) | (2 | ) | (1 | ) | |||||||
Allowance for Equity Funds Used During Construction | (2 | ) | (1 | ) | (1 | ) | |||||||
Deferred Tax Asset Valuation Allowance | $ | — | 2 | — | |||||||||
Investment Tax Credit Basis Adjustment – Creation of Regulatory Asset | — | (11 | ) | — | |||||||||
Other | 2 | 1 | (1 | ) | |||||||||
Total Federal and State Income Tax Expense | $ | 58 | $ | 48 | $ | 39 | |||||||
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. | |||||||||||||
Income tax expense included in the income statements consists of the following: | |||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Millions of Dollars | |||||||||||||
Current Tax Expense (Benefit): | |||||||||||||
Federal | $ | (1 | ) | $ | (8 | ) | $ | (4 | ) | ||||
State | — | (2 | ) | (2 | ) | ||||||||
Total Current Tax Expense (Benefit) | (1 | ) | (10 | ) | (6 | ) | |||||||
Federal | $ | 54 | 47 | 38 | |||||||||
Federal Investment Tax Credits | (4 | ) | (1 | ) | — | ||||||||
State | 9 | 12 | 7 | ||||||||||
Total Deferred Tax Expense (Benefit) | 59 | 58 | 45 | ||||||||||
Total Federal and State Income Tax Expense | $ | 58 | $ | 48 | $ | 39 | |||||||
The significant components of deferred income tax assets and liabilities consist of the following: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Millions of Dollars | |||||||||||||
Gross Deferred Income Tax Assets: | |||||||||||||
Capital Lease Obligations | $ | 96 | $ | 127 | |||||||||
Net Operating Loss Carryforwards | 187 | 104 | |||||||||||
Customer Advances and Contributions in Aid of Construction | 19 | 19 | |||||||||||
Alternative Minimum Tax Credit | 24 | 24 | |||||||||||
Accrued Postretirement Benefits | 23 | 23 | |||||||||||
Emission Allowance Inventory | 10 | 10 | |||||||||||
Investment Tax Credit Carryforward | 31 | 6 | |||||||||||
Other | 54 | 38 | |||||||||||
Total Gross Deferred Income Tax Assets | 444 | 351 | |||||||||||
Deferred Tax Assets Valuation Allowance | (2 | ) | (2 | ) | |||||||||
Gross Defined Income Tax Liabilities: | |||||||||||||
Plant - Net | (699 | ) | (615 | ) | |||||||||
Capital Lease Assets - Net | (74 | ) | (47 | ) | |||||||||
Pensions | (27 | ) | (22 | ) | |||||||||
PPFAC | (8 | ) | (2 | ) | |||||||||
Other | (24 | ) | (20 | ) | |||||||||
Total Gross Deferred Income Tax Liabilities | (832 | ) | (706 | ) | |||||||||
Net Deferred Income Tax Liabilities | $ | (390 | ) | $ | 357 | ) | |||||||
The net deferred income tax liability on the balance sheets is as follows: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Millions of Dollars | |||||||||||||
Deferred Income Taxes – Current Assets | $ | 102 | $ | 71 | |||||||||
Deferred Income Taxes – Noncurrent Liabilities | $ | (492 | ) | $ | (428 | ) | |||||||
Net Deferred Income Tax Liability | $ | (390 | ) | $ | (357 | ) | |||||||
TEP has recorded a $2 million valuation allowance against state tax credit carryforwad deferred tax assets at December 31, 2014. Management believes TEP will not produce sufficient taxable income to use all state tax credits before they expire. | |||||||||||||
As of December 31, 2014, TEP had the following carryforward amounts: | |||||||||||||
Amount | Expiring Year | ||||||||||||
Millions of Dollars | |||||||||||||
Federal Net Operating Loss | $ | 507 | 2031-34 | ||||||||||
State Net Operating Loss | 237 | 2016-34 | |||||||||||
State Credits | 8 | 2016-19 | |||||||||||
Alternative Minimum Tax Credit | 24 | None | |||||||||||
Investment Tax Credits | 31 | 2032-34 | |||||||||||
Uncertain Tax Positions | |||||||||||||
A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Millions of Dollars | |||||||||||||
Unrecognized Tax Benefits, Beginning of Year | $ | 2 | $ | 23 | |||||||||
Additions Based on Tax Positions Taken in the Current Year | 2 | 1 | |||||||||||
Reductions of Positions from Prior Year Based on Tax Authority Ruling | — | (22 | ) | ||||||||||
Unrecognized Tax Benefits, End of Year | $ | 4 | $ | 2 | |||||||||
Unrecognized tax benefits, if recognized, would not reduce income tax expense at December 31, 2013 and December 31, 2014. TEP recognized a $1 million reduction to interest expense in 2013 and no reduction in 2014. TEP had no interest payable balances at December 31, 2014 and December 31, 2013. We have no penalties accrued in the years presented. | |||||||||||||
In February 2013, we received a favorable ruling from the Internal Revenue Service (IRS) allowing us to deduct up-front incentive payments to customers who install renewable energy resources. These customers transfer environmental attributes or RECs associated with their renewable installations to us over the expected life of the contract for an up-front incentive payment based on the generating capacity of their installation. As a result of the IRS ruling in the first quarter of 2013, TEP reduced unrecognized tax benefits by $22 million. The changes in tax benefits primarily affected the balance sheets. | |||||||||||||
TEP has been audited by the IRS through tax year 2010. TEP is not currently under audit by any state tax agencies. The balance in unrecognized tax benefits could change in the next 12 months as a result of IRS audits, but we are unable to determine the amount of change. | |||||||||||||
Tangible Property Regulations | |||||||||||||
In September 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment. The adoption of these regulations by TEP resulted in a $22 million increase to plant-related deferred tax liabilities and net operating loss deferred tax assets at December 31, 2014. |
QUARTERLY_FINANCIAL_DATA_UNAUD
QUARTERLY FINANCIAL DATA (UNAUDITED | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||
QUARTERLY FINANCIAL DATA (UNAUDITED | QUARTERLY FINANCIAL DATA (UNAUDITED) | ||||||||||||||||
Our quarterly financial information is unaudited but, in management’s opinion, includes all adjustments necessary for a fair presentation. Our utility business is seasonal in nature. Peak sales periods for TEP generally occur during the summer. Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. | |||||||||||||||||
First | Second | Third | Fourth | ||||||||||||||
Thousands of Dollars | |||||||||||||||||
2014 | |||||||||||||||||
Operating Revenue | $ | 255,513 | $ | 321,618 | $ | 387,411 | $ | 305,359 | |||||||||
Operating Income | 31,999 | 79,653 | 84,898 | 34,138 | |||||||||||||
Net Income | 9,172 | 38,725 | 39,644 | 14,797 | |||||||||||||
2013 | |||||||||||||||||
Operating Revenue | $ | 247,751 | $ | 304,263 | $ | 371,239 | $ | 273,437 | |||||||||
Operating Income | 22,747 | 53,433 | 123,177 | 31,014 | |||||||||||||
Net Income | 1,478 | 30,787 | 64,167 | 4,910 | |||||||||||||
Schedule_IIValuation_and_Quali
Schedule II-Valuation and Qualifying Accounts | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Valuation and Qualifying Accounts [Abstract] | |||||||||
Schedule II-Valuation and Qualifying Accounts | Schedule II—Valuation and Qualifying Accounts | ||||||||
Allowance for Doubtful Accounts(1) | Beginning Balance | Additions- | Deductions | Ending Balance | |||||
Charged to | |||||||||
Income | |||||||||
Millions of Dollars | |||||||||
Year-Ended December 31, | |||||||||
2014 | $ 5 | $ 2 | $ 2 | $ 5 | |||||
2013 | 5 | 2 | 2 | 5 | |||||
2012 | 14 | 3 | 12 | 5 | |||||
Other Reserves(2) | Beginning Balance | Ending Balance | |||||||
Millions of Dollars | |||||||||
Year Ended December 31, | |||||||||
2014 | $ 4 | $ 5 | |||||||
2013 | 8 | 4 | |||||||
2012 | 4 | 8 | |||||||
(1) | TEP records additions to the Allowance for Doubtful Accounts based on historical experience and any specific customer collection issues identified. Deductions principally reflect amounts charged off as uncollectible, less amounts recovered. Amounts include reserves for trade receivables, wholesales sales, and in-kind transmission imbalances. | ||||||||
(2) | As the Other Reserves are not individually significant, additions and deductions need not be disclosed. Other reserves are made up of reserves for sales tax audits, litigation matters, and damages billable to third parties. |
NATURE_OF_OPERATIONS_AND_FINAN2
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies) | 3 Months Ended | 12 Months Ended | ||||||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||||||
Accounting Policies [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), including specific accounting guidance for regulated operations and the Securities and Exchange Commission’s (SEC) interim reporting requirements. See Note 2. The condensed consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stations and transmission facilities with both affiliated and non-affiliated entities. TEP’s proportionate share of jointly owned facilities is recorded as Utility Plant on the condensed consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the condensed consolidated statements of income. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2014 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. | ||||||||||||||
In 2014, following the acquisition of UNS Energy by Fortis, TEP 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. | ||||||||||||||
Recently Adopted Accounting Pronouncements | RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS | |||||||||||||
In 2015, we adopted accounting guidance that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. The adoption of this guidance did not have any impact on our disclosures, financial condition, results of operations, or cash flows. | ||||||||||||||
Nature of Operations | 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. 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. | |||||||||||||
Basis Of Presentation | BASIS OF PRESENTATION | |||||||||||||
TEP’s consolidated financial statements and disclosures are presented in accordance with generally accepted accounting principles (GAAP) in the United States which includes specific accounting guidance for regulated operations. See Note 2 of Notes to Consolidated Financial Statements. The consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stations and transmission facilities with non-affiliated entities. TEP’s proportionate share of jointly owned facilities is recorded as Utility Plant on the consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the consolidated statements of income. See Note 3 of Notes to Consolidated Financial Statements. | ||||||||||||||
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 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. | ||||||||||||||
Reclassification, Policy | REVISION OF BALANCE SHEET AND STATEMENT OF CAPITALIZATION AS OF DECEMBER 31, 2013 | |||||||||||||
TEP revised its December 31, 2013 balance sheet and statement of capitalization to correct an immaterial 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. The notes that follow have been updated for this revision. | ||||||||||||||
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. | |||||||||||||
Use of Accounting Estimates | USE OF ACCOUNTING ESTIMATES | |||||||||||||
Management uses estimates and assumptions when preparing financial statements under GAAP. These estimates and assumptions affect: | ||||||||||||||
• | Assets and liabilities on our balance sheets at the dates of the financial statements; | |||||||||||||
• | Our disclosures about contingent assets and liabilities at the dates of the financial statements; and | |||||||||||||
• | Our revenues and expenses in our income statements during the periods presented. | |||||||||||||
Because these estimates involve judgments based upon our evaluation of relevant facts and circumstances, actual results may differ from the estimates. | ||||||||||||||
Accounting for Regulated Operations | ACCOUNTING FOR REGULATED OPERATIONS | |||||||||||||
We apply accounting standards that recognize the economic effects of rate regulation. As a result, we capitalize certain costs that would be recorded as expense or in Accumulated Other Comprehensive Income (AOCI) by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in the rates charged to retail customers or to wholesale customers through transmission tariffs. Regulatory liabilities generally represent expected future costs that have already been collected from customers or items that are expected to be returned to customers through future rate reductions. | ||||||||||||||
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. We evaluate regulatory assets each period and believe recovery is probable. If future recovery of costs ceases to be probable, the assets would be written off as a charge to current period earnings or AOCI. See Note 2 of Notes to Consolidated Financial Statements. | ||||||||||||||
TEP applies regulatory accounting as the following conditions exist: | ||||||||||||||
• | An independent regulator sets rates; | |||||||||||||
• | The regulator sets the rates to recover the specific enterprise’s costs of providing service; and | |||||||||||||
• | Rates are set at levels that will recover the entity’s costs and can be charged to and collected from customers. | |||||||||||||
Cash and Cash Equivalents | CASH AND CASH EQUIVALENTS | |||||||||||||
We consider all highly liquid investments with a remaining maturity of three months or less at acquisition to be cash equivalents. | ||||||||||||||
Restricted Cash | RESTRICTED CASH | |||||||||||||
Cash balances that are restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property—Other on the balance sheets. Restricted cash was $2 million at December 31, 2014 and December 31, 2013. | ||||||||||||||
Utility Plant | UTILITY PLANT | |||||||||||||
Utility Plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. We report utility plant at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction (AFUDC), less contributions in aid of construction. | ||||||||||||||
We record the cost of repairs and maintenance, including planned major overhauls, to Operations and Maintenance (O&M) expense in the income statement as costs are incurred. | ||||||||||||||
When a unit of regulated property is retired, we reduce accumulated depreciation by the original cost plus removal costs less any salvage value. There is no income statement impact. | ||||||||||||||
AFUDC and Capitalized Interest | AFUDC and Capitalized Interest | |||||||||||||
AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction. The capitalized interest that relates to debt is recorded as a reduction in Interest Expense in the income statement. The capitalized cost for equity funds is recorded as Other Income in the income statement. | ||||||||||||||
The average AFUDC rates on regulated construction expenditures are included in the table below: | ||||||||||||||
2014 | 2013 | 2012 | ||||||||||||
Average AFUDC Rates | 7.3 | % | 7.38 | % | 7.22 | % | ||||||||
Depreciation | Depreciation | |||||||||||||
We compute depreciation for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note 2 and Note 3 of Notes to Consolidated Financial Statements. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs. Below are the summarized average annual depreciation rates for all utility plant: | ||||||||||||||
2014 | 2013 | 2012 | ||||||||||||
Average Annual Depreciation Rates | 2.99 | % | 3.16 | % | 3.22 | % | ||||||||
TEP Utility Plant Under Capital Leases | Utility Plant Under Capital Leases | |||||||||||||
TEP financed the following generation assets with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capital lease expense incurred consists of Amortization Expense (see Note 3 of Notes to Consolidated Financial Statements) and Interest Expense—Capital Leases. The lease terms are described in Note 5 of Notes to Consolidated Financial Statements. | ||||||||||||||
Computer Software Costs | Computer Software Costs | |||||||||||||
We capitalize costs incurred to purchase and develop internal use computer software and amortize those costs over the estimated economic life of the product. If the software is no longer useful, we immediately charge capitalized computer software costs to expense. | ||||||||||||||
Investments in Lease Debt and Equity | INVESTMENTS IN LEASE EQUITY | |||||||||||||
Prior to December 2014, TEP held a 14.1% equity interest in Springerville Unit 1 and a 7% interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 10 of Notes to Consolidated Financial Statements. | ||||||||||||||
TEP accounted for its equity interest in the Springerville Unit 1 Lease trust using the equity method. In December 2014, following the purchase of an additional undivided interest in Springerville Unit 1, TEP transferred the balance of its investment in lease equity to Plant in Service. | ||||||||||||||
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS | |||||||||||||
TEP has identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its photovoltaic assets as a result of entering into various ground leases. We record a liability for a legal ARO in the period in which it is incurred if it can be reasonably estimated. When a new obligation is recorded, we capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. We record the increase in the liability due to the passage of time by recognizing accretion expense in O&M expense and depreciate the capitalized cost over the useful life of the related asset or when applicable, the terms of the lease subject to ARO requirements. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs. | ||||||||||||||
Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. We recover those amounts in the rates charged to retail customers and have recorded an obligation for estimated costs of removal as regulatory liabilities. | ||||||||||||||
Evaluation of Assets for Impairment | EVALUATION OF ASSETS FOR IMPAIRMENT | |||||||||||||
We evaluate long-lived assets and investments for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates. | ||||||||||||||
Deferred Financing Costs | DEFERRED FINANCING COSTS | |||||||||||||
We defer the costs to issue debt and amortize such costs to interest expense on a straight-line basis over the life of the debt as this approximates the effective interest method. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs. | ||||||||||||||
We defer and amortize the gains and losses on reacquired debt associated with regulated operations to interest expense over the remaining life of the original debt. | ||||||||||||||
Operating Revenues | OPERATING REVENUES | |||||||||||||
We recognize revenues related to the sale of energy when services or commodities are delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates. | ||||||||||||||
For purchased power and wholesale sales contracts that are settled financially, TEP nets the sales contracts with the purchase power contracts and reflects the net amount as Electric Wholesale Sales. | ||||||||||||||
TEP recognizes monthly management fees in Other Revenues as the operator of 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 Agriculture Improvement and Power District (SRP). Additionally, Other Revenues include reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and the Springerville Coal Handling Facilities. The offsetting expenses are recorded in the respective line items of the income statements based on the nature of services provided. As the operating agent for Tri-State and SRP, TEP may earn performance incentives based on unit availability which are recognized in Other Revenues in the period earned. | ||||||||||||||
The ACC has authorized mechanisms for Lost Fixed Cost Recovery (LFCR) related to kWh sales lost due to Energy Efficiency (EE) Standards and Distributed Generation (DG). We recognize revenues in the period that verifiable energy savings occur. Revenue recognition related to the LFCR creates a regulatory asset until such time as the revenue is collected. | ||||||||||||||
Allowance for Doubtful Accounts | ALLOWANCE FOR DOUBTFUL ACCOUNTS | |||||||||||||
We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions. | ||||||||||||||
Inventory | INVENTORY | |||||||||||||
We value materials, supplies and fuel inventory at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost (even if in excess of market) will be recovered in retail rates. We capitalize handling and procurement costs (such as labor, overhead costs, and transportation costs) as part of the cost of the inventory. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials. | ||||||||||||||
Recovery Of Fuel And Purchased Energy Costs | PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE | |||||||||||||
We recover actual fuel, purchased power and transmission costs to provide electric service to retail customers through base fuel rates and a Purchased Power and Fuel Adjustment Clause (PPFAC); the ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 2 of Notes to Consolidated Financial Statements. | ||||||||||||||
Renewable Energy Credits | RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS | |||||||||||||
The ACC’s Renewable Energy Standard (RES) requires TEP to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements in 2025, with distributed generation accounting for 30% of the annual renewable energy requirement. TEP must file an annual RES implementation plan for review and approval by the ACC. The approved cost of carrying out this plan is recovered from retail customers through the RES surcharge. The ACC has also approved recovery of operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects through the RES tariff until such costs are reflected in retail customer rates. | ||||||||||||||
TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC’s EE Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs. The Electric EE Standards require increasing annual targeted retail Kilowatt-hours (kWh) savings equal to 22% by 2020. | ||||||||||||||
Any RES or DSM surcharge collections above or below the costs incurred to implement the plans are deferred and reflected in the financial statements as a regulatory asset or liability. TEP recognizes RES and DSM surcharge revenue in Electric Retail Sales in amounts necessary to offset recognized qualifying expenditures. | ||||||||||||||
RENEWABLE ENERGY CREDITS | ||||||||||||||
The ACC measures compliance with the RES requirements through Renewable Energy Credits (RECs). A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the PPFAC. | ||||||||||||||
When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as Other Assets, and a corresponding regulatory liability, to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes Purchased Power expense and Other Revenues in an equal amount. See Note 2 of Notes to Consolidated Financial Statements. | ||||||||||||||
Income Taxes | INCOME TAXES | |||||||||||||
Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on our balance sheets. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. We reduce deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or the entire deferred income tax asset will not be realized. | ||||||||||||||
Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Other Interest Expense. | ||||||||||||||
Prior to 1990, TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets – Noncurrent includes income taxes recoverable through future rates, which reflects the future revenues due to TEP from ratepayers as these tax benefits reverse. See Note 2 of Notes to Consolidated Financial Statements. | ||||||||||||||
We account for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as Regulatory Liabilities – Noncurrent and amortized as a reduction in Income Tax Expense over the tax life of the underlying asset. Income Tax Expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as regulatory assets effective July 1, 2013 due to the 2013 TEP Rate Order. All other federal and state income tax credits are treated as a reduction to Income Tax Expense in the year the credit arises. | ||||||||||||||
Income tax liabilities are allocated to TEP based on its taxable income as reported in the FortisUS Inc. consolidated tax return. | ||||||||||||||
Taxes Other Than Income Taxes | TAXES OTHER THAN INCOME TAXES | |||||||||||||
We act as conduits or collection agents for sales taxes, utility taxes, franchise fees, and regulatory assessments. As we bill customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable to governmental agencies on the balance sheet for these taxes and assessments. These amounts are not reflected in the income statements. | ||||||||||||||
Derivative Instruments | DERIVATIVE INSTRUMENTS | |||||||||||||
We use various physical and financial derivative instruments, including forward contracts, financial swaps and call and put options, to meet forecasted load and reserve requirements, to reduce our exposure to energy commodity price volatility and to hedge our interest rate risk exposure. For all derivative instruments that do not meet the normal purchase or normal sale scope exception, we recognize derivative instruments as either assets or liabilities on the consolidated balance sheets and measure those instruments at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. | ||||||||||||||
Cash Flow Hedges | ||||||||||||||
TEP hedges the cash flow risk associated with unfavorable changes in the variable interest rates related to the leveraged lease arrangements for the Springerville Common Lease and variable rate industrial development revenue or pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that does not qualify for regulatory recovery using a six-year power purchase swap agreement. TEP accounts for cash flow hedges as follows: | ||||||||||||||
• | The effective portion of the change in the fair value is recorded in AOCI and the ineffective portion, if any, is recognized in earnings; and | |||||||||||||
• | When TEP determines a contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP recognizes the change in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs. | |||||||||||||
We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain highly effective in offsetting changes in the cash flows of hedged items. | ||||||||||||||
Energy Contracts—Regulatory Recovery | ||||||||||||||
TEP is authorized to recover the costs of hedging activities entered into to mitigate energy price risk for retail customers. We record unrealized gains and losses on these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC mechanism. | ||||||||||||||
Energy Contracts—No Regulatory Recovery | ||||||||||||||
From time to time, TEP may enter into forward contracts with long-term wholesale customers that qualify as derivatives. We record unrealized gains and losses on these energy derivatives in the income statement as they do not qualify for regulatory recovery. | ||||||||||||||
Master Netting Agreements | ||||||||||||||
We have elected gross presentation for our derivative contracts under master netting agreements and collateral positions. We separate all derivatives into current and long-term portions on the balance sheet. | ||||||||||||||
Normal Purchases and Normal Sales | ||||||||||||||
We enter into forward energy purchase and sales contracts, including options, with counterparties that have generating capacity to support our current load forecasts or counterparties that have load serving requirements. We have elected the normal purchase or normal sales exception for these contracts which are not required to be measured at fair value and are accounted for on an accrual basis. | ||||||||||||||
Commodity Trading | ||||||||||||||
We did not engage in trading of derivative financial instruments for the periods presented. | ||||||||||||||
Pension and Other Retiree Benefits | PENSION AND OTHER RETIREE BENEFITS | |||||||||||||
We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. We also provide limited health care and life insurance benefits for retirees. | ||||||||||||||
We recognize the underfunded status of our defined benefit pension plans as a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit obligation for the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers and expect to recover these costs over the estimated service lives of employees. | ||||||||||||||
Additionally, we maintain a Supplemental Executive Retirement Plan (SERP) for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI. | ||||||||||||||
Pension and other retiree benefit expenses are determined by actuarial valuations based on assumptions that we evaluate annually. See Note 8 of Notes to Consolidated Financial Statements. |
RELATED_PARTY_TRANSACTIONS_Tab
RELATED PARTY TRANSACTIONS (Tables) | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||||||||||||||
Related Party Transactions [Abstract] | ||||||||||||||||||||||
Schedule of Related Party Transactions | At March 31, 2015 and December 31, 2014, our balance sheets include the following intercompany balances: | The following table summarizes related party transactions: | ||||||||||||||||||||
Balances at | Years Ended December 31, | |||||||||||||||||||||
March 31, 2015 | December 31, 2014 | 2014 | 2013 | 2012 | ||||||||||||||||||
Millions of Dollars | Millions of Dollars | |||||||||||||||||||||
Receivables from Related Parties | Wholesale Sales - TEP to UNS Electric(1) | $ | 4 | $ | 1 | $ | 2 | |||||||||||||||
UNS Electric | $ | 4 | $ | 4 | Wholesale Sales - UNS Electric to TEP(1) | 4 | 2 | 1 | ||||||||||||||
UNS Gas | 1 | 1 | Control Area Services - TEP to UNS Electric(2) | 3 | 4 | 3 | ||||||||||||||||
Common Costs - TEP to UNS Energy Affiliates(3) | 13 | 12 | 12 | |||||||||||||||||||
Total Due from Related Parties | $ | 5 | $ | 5 | Supplemental Workforce - UNS Energy Affiliate to TEP(4) | 16 | 16 | 17 | ||||||||||||||
Corporate Services - UNS Energy to TEP(5) | 14 | 5 | 2 | |||||||||||||||||||
Payables to Related Parties | Corporate Services - UNS Energy Affiliates to TEP(6) | 1 | 1 | 1 | ||||||||||||||||||
SES | $ | 3 | $ | 2 | ||||||||||||||||||
UNS Energy | 1 | — | ||||||||||||||||||||
UNS Electric | — | 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. | |||||||||||||||||||||
Total Due to Related Parties | $ | 4 | $ | 3 | -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 | Corporate costs at UNS Energy, such as merger costs and legal and audit fees, are allocated to its subsidiaries using the Massachusetts’ Formula, an industry accepted method of allocating common costs to affiliated entities. TEP’s allocation is approximately 81% of UNS Energy’s allocated costs. | |||||||||||||||||||||
The following table summarizes related party transactions: | -6 | All Corporate Services (e.g., 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. | ||||||||||||||||||||
At December 31, 2014 and December 31, 2013, our Balance Sheets include the following intercompany balances: | ||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||
2015 | 2014 | |||||||||||||||||||||
Millions of Dollars | December 31, 2014 | December 31, 2013 | ||||||||||||||||||||
Wholesale Sales—TEP to UNS Electric (1) | $ | 2 | $ | — | Millions of Dollars | |||||||||||||||||
Control Area Services—TEP to UNS Electric (2) | — | 1 | Receivables from Related Parties | |||||||||||||||||||
Common Costs—TEP to UNS Energy Affiliates (3) | 3 | 3 | UNS Electric | $ | 4 | $ | 3 | |||||||||||||||
Supplemental Workforce—SES to TEP (4) | 4 | 4 | UNS Gas | 1 | 2 | |||||||||||||||||
Corporate Services—UNS Energy to TEP (5) | 1 | 1 | UNS Energy | — | 1 | |||||||||||||||||
Total Due from Related Parties | $ | 5 | $ | 6 | ||||||||||||||||||
(1) | TEP sells power to UNS Electric at prevailing market prices. | |||||||||||||||||||||
(2) | TEP charges UNS Electric for control area services under a FERC-accepted Control Area Services Agreement. | Payables to Related Parties | ||||||||||||||||||||
(3) | Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable. | SES | $ | 2 | $ | 2 | ||||||||||||||||
(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. | UNS Electric | 1 | — | ||||||||||||||||||
(5) | Corporate costs at UNS Energy, such as Fortis management fees, legal fees, and audit fees, are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP’s allocation is approximately 81% of UNS Energy’s allocated costs. For the three months ended March 31, 2015 these costs included approximately $1 million in Fortis management fees and for the three months ended March 31, 2014 these costs included approximately $1 million in merger related costs. | UNS Energy | — | 7 | ||||||||||||||||||
Total Due to Related Parties | $ | 3 | $ | 9 | ||||||||||||||||||
COMMITMENTS_CONTINGENCIES_AND_1
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS (Tables) | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitments | In addition to those reported in our 2014 Annual Report on Form 10-K, TEP entered into the following long-term commitments through March 31, 2015: | At December 31, 2014, TEP had the following firm, non-cancellable, minimum purchase obligations and operating leases. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||
Fuel, Including Transportation | $ | 1 | $ | 2 | $ | 2 | $ | 2 | $ | 2 | $ | 47 | $ | 56 | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||||||
Purchased Power | 30 | 11 | — | — | — | — | 41 | Fuel, Including Transportation | $ | 76 | $ | 78 | $ | 76 | $ | 49 | $ | 49 | $ | 285 | $ | 613 | ||||||||||||||||||||||||||||||||||||
Purchased Power | 22 | 7 | — | — | — | — | 29 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Total Purchase Commitments | $ | 31 | $ | 13 | $ | 2 | $ | 2 | $ | 2 | $ | 47 | $ | 97 | Transmission | 6 | 6 | 6 | 6 | 4 | 16 | 44 | ||||||||||||||||||||||||||||||||||||
Renewable Power Purchase Agreements | 45 | 45 | 45 | 45 | 44 | 565 | 789 | |||||||||||||||||||||||||||||||||||||||||||||||||||
RES Performance-Based Incentives | 8 | 8 | 8 | 8 | 8 | 76 | 116 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Leases: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Land Easements and Rights-of-Way | 2 | 1 | 1 | 1 | 2 | 77 | 84 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Operating Leases Other | 1 | 1 | 1 | 1 | 1 | 5 | 10 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Total Purchase Commitments | $ | 160 | $ | 146 | $ | 137 | $ | 110 | $ | 108 | $ | 1,024 | $ | 1,685 | ||||||||||||||||||||||||||||||||||||||||||||
Schedule of Mercury Emission Control Costs | TEP’s share of the estimated costs to comply with the MATS rules includes the following: | TEP’s share of the estimated costs to comply with the MATS rules includes the following: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Mercury Emissions Control Costs: | Navajo | Springerville(1) | Estimated Mercury Emissions Control Costs: | Navajo | Springerville (1) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capital Expenditures | $ | 1 | $ | 5 | Capital Expenditures | $ | 1 | $ | 5 | |||||||||||||||||||||||||||||||||||||||||||||||||
Annual O&M Expenses | 1 | 1 | Annual O&M Expenses | 1 | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
(1) | Total capital expenditures and annual O&M expenses represent amounts for Springerville Units 1 & 2, with estimated costs split equally between the two units. In January 2015, TEP completed the purchase of 49.5% of Springerville Unit 1. With the completion of the purchase, Third Party Owners are 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. | (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 owns 49.5% of Springerville Unit 1 with the close of the lease option purchases in December 2014 and January 2015; Third-Party Owners are responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP continues to be responsible for 100% of environmental costs attributable to Springerville Unit 2. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regional Haze Rules, Schedule of Environmental Loss Contingencies by Site | TEP’s estimated costs involved in meeting these rules are: | The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018. 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 | San | Four | Sundt(4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Juan(1) | Corners(3) | Estimated NOx Emissions Control Costs: | Navajo (1) | San Juan (2) | Four Corners (3) | Sundt (4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capital Expenditures | $ | 28 | $ | 37 | $ | 44 | $ | 12 | Capital Expenditures | $ | 28 | $ | 37 | $ | 35 | $ | 12 | |||||||||||||||||||||||||||||||||||||||||
Annual O&M Expenses | 1 | 1 | 2 | 6-May | Annual O&M Expenses | 1 | 1 | 2 | 6-May | |||||||||||||||||||||||||||||||||||||||||||||||||
(1) | In August 2014, the EPA published a final Federal Implementation Plan (FIP) 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. The final BART includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA which option will be implemented. 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 $28 million with O&M on the baghouses expected to be less than $1 million per year. | (1) | In August 2014, the EPA published a final FIP 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. The plant has until December 2019 to notify the EPA which option will be implemented. 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 $28 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 revised State Implementation Plan (SIP) 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 February 2016. TEP owns 50% of Units 1 and 2 at San Juan. TEP expects its share of the cost to install SNCR technology on San Juan Unit 1 to be approximately $12 million. Additionally, the SIP approval references a New Source Review permit issued by the New Mexico Environment Department in November 2013 which, among other things, calls for balanced draft upgrades on San Juan Unit 1 to reduce particulate matter emissions. Public Service Company of New Mexico (PNM), the operator of San Juan, is currently installing SNCR and making the necessary balanced draft modifications to San Juan Unit 1. TEP’s share of the balanced draft upgrades is expected to be approximately $25 million for a total of $37 million in capital expenditures. TEP’s share of incremental annual operating costs for SNCR for San Juan Unit 1 is estimated at $1 million. Prior to the shutdown of any units at San Juan, PNM, the operator, must first obtain New Mexico Public Regulation Commission approval. At March 31, 2015, the net book value of TEP’s share in San Juan Unit 2 was $109 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC’s authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2. | (2) | In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) 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) and Balance Draft technology on Units 1 and 4 by February 2016. Prior to the shutdown of any units at San Juan, Public Service Company of New Mexico (PNM), the operator, must first obtain New Mexico Public Regulation Commission approval. TEP owns 50% of San Juan Unit 2. At December 31, 2014, the net book value of TEP’s share in San Juan Unit 2 was $110 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC’s authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
(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 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5. | (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 and 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, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At March 31, 2015, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities. | (4) | In June 2014, the EPA issued a final rule that would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At December 31, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities. |
EMPLOYEE_BENEFIT_PLANS_Tables
EMPLOYEE BENEFIT PLANS (Tables) | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||||||||||||||||||||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||
Components of Net Periodic Benefit Cost | Net periodic benefit plan cost includes the following components: | Net periodic benefit plan cost includes the following components: | ||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree Benefits | |||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | Pension Benefits | Other Retiree Benefits | ||||||||||||||||||||||||||||||||||||||||
2015 | 2014 | 2015 | 2014 | Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||
Millions of Dollars | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||
Service Cost | $ | 3 | $ | 2 | $ | 1 | $ | 1 | Service Cost | $ | 10 | $ | 11 | $ | 9 | $ | 4 | $ | 3 | $ | 3 | |||||||||||||||||||||
Interest Cost | 4 | 4 | 1 | — | Interest Cost | 16 | 14 | 15 | 3 | 3 | 3 | |||||||||||||||||||||||||||||||
Expected Return on Plan Assets | (6 | ) | (5 | ) | — | — | Expected Return on Plan Assets | (21 | ) | (19 | ) | (17 | ) | (1 | ) | (1 | ) | — | ||||||||||||||||||||||||
Actuarial Loss Amortization | 2 | 1 | — | — | Actuarial Loss Amortization | 3 | 8 | 7 | — | — | — | |||||||||||||||||||||||||||||||
Net Periodic Benefit Cost | $ | 3 | $ | 2 | $ | 2 | $ | 1 | Net Periodic Benefit Cost | $ | 8 | $ | 14 | $ | 14 | $ | 6 | $ | 5 | $ | 6 | |||||||||||||||||||||
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: | The following tables set forth a reconciliation of changes in the fair value of pension assets classified as Level 3 in the fair value hierarchy. There were no transfers in or out of Level 3. | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | Private Equity | Real Estate | Total | |||||||||||||||||||||||||||||||||||||||
2015 | 2014 | Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | Beginning Balance at January 1, 2014 | $ | 7 | $ | 14 | $ | 21 | |||||||||||||||||||||||||||||||||||
Balances at December 31 | $ | (9 | ) | $ | (2 | ) | Actual Return on Plan Assets: | |||||||||||||||||||||||||||||||||||
Realized/Unrealized Gains/(Losses) Recorded to: | Assets Held at Reporting Date | 1 | 2 | 3 | ||||||||||||||||||||||||||||||||||||||
Net Regulatory Assets/Liabilities—Derivative Instruments | (2 | ) | (1 | ) | Purchases, Sales, and Settlements | (1 | ) | — | (1 | ) | ||||||||||||||||||||||||||||||||
Settlements | (1 | ) | 1 | |||||||||||||||||||||||||||||||||||||||
Ending Balance at December 31, 2014 | $ | 7 | $ | 16 | $ | 23 | ||||||||||||||||||||||||||||||||||||
Balances at March 31 | $ | (12 | ) | $ | (2 | ) | ||||||||||||||||||||||||||||||||||||
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period | $ | (3 | ) | $ | — | |||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||
Private Equity | Real Estate | Total | ||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Beginning Balance at January 1, 2013 | $ | 6 | $ | 13 | $ | 19 | ||||||||||||||||||||||||||||||||||||
Actual Return on Plan Assets: | ||||||||||||||||||||||||||||||||||||||||||
Assets Held at Reporting Date | 1 | 1 | 2 | |||||||||||||||||||||||||||||||||||||||
Ending Balance at December 31, 2013 | $ | 7 | $ | 14 | $ | 21 | ||||||||||||||||||||||||||||||||||||
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: | ||||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Balances at Beginning of Year | $ | (2 | ) | $ | — | |||||||||||||||||||||||||||||||||||||
Realized/Unrealized/(Losses) Recorded to: | ||||||||||||||||||||||||||||||||||||||||||
Net Regulatory Assets/Liabilities – Derivative Instruments | (8 | ) | (2 | ) | ||||||||||||||||||||||||||||||||||||||
Settlements | 1 | — | ||||||||||||||||||||||||||||||||||||||||
Balances at End of Year | $ | (9 | ) | $ | (2 | ) | ||||||||||||||||||||||||||||||||||||
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period | $ | (8 | ) | $ | (1 | ) | ||||||||||||||||||||||||||||||||||||
Schedule of Amounts Recognized in Balance Sheet | The pension and other retiree benefit related amounts (excluding tax balances) included on our balance sheet are: | |||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree | |||||||||||||||||||||||||||||||||||||||||
Benefits | ||||||||||||||||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Regulatory Pension Asset Included in Other Regulatory Assets | $ | 117 | $ | 71 | $ | 9 | $ | 4 | ||||||||||||||||||||||||||||||||||
Accrued Benefit Liability Included in Accrued Employee Expenses | (1 | ) | (1 | ) | (2 | ) | (2 | ) | ||||||||||||||||||||||||||||||||||
Accrued Benefit Liability Included in Pension and Other Retiree Benefits | (71 | ) | (23 | ) | (67 | ) | (62 | ) | ||||||||||||||||||||||||||||||||||
Accumulated Other Comprehensive Loss (related to SERP) | 5 | 2 | — | — | ||||||||||||||||||||||||||||||||||||||
Net Amount Recognized | $ | 50 | $ | 49 | $ | (60 | ) | $ | (60 | ) | ||||||||||||||||||||||||||||||||
Schedule of Changes in Funded Status | We measured the actuarial present values of all pension benefit obligations and other retiree benefit plans at December 31, 2014 and December 31, 2013. The table below includes all of TEP’s plans. All plans have projected benefit obligations in excess of fair value of plan assets for each period presented. The status of our pension benefit and other retiree benefit plans are summarized below: | |||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree Benefits | |||||||||||||||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Change in Projected Benefit Obligation | ||||||||||||||||||||||||||||||||||||||||||
Benefit Obligation at Beginning of Year | $ | 330 | $ | 357 | $ | 74 | $ | 77 | ||||||||||||||||||||||||||||||||||
Actuarial (Gain) Loss | 67 | (35 | ) | 5 | (5 | ) | ||||||||||||||||||||||||||||||||||||
Interest Cost | 16 | 14 | 3 | 3 | ||||||||||||||||||||||||||||||||||||||
Service Cost | 10 | 11 | 4 | 3 | ||||||||||||||||||||||||||||||||||||||
Benefits Paid | (16 | ) | (17 | ) | (5 | ) | (4 | ) | ||||||||||||||||||||||||||||||||||
Projected Benefit Obligation at End of Year | 407 | 330 | 81 | 74 | ||||||||||||||||||||||||||||||||||||||
Change in Plan Assets | ||||||||||||||||||||||||||||||||||||||||||
Fair Value of Plan Assets at Beginning of Year | 307 | 275 | 10 | 7 | ||||||||||||||||||||||||||||||||||||||
Actual Return on Plan Assets | 35 | 27 | 1 | 1 | ||||||||||||||||||||||||||||||||||||||
Benefits Paid | (16 | ) | (17 | ) | (5 | ) | (4 | ) | ||||||||||||||||||||||||||||||||||
Employer Contributions (1) | 9 | 22 | 6 | 6 | ||||||||||||||||||||||||||||||||||||||
Fair Value of Plan Assets at End of Year | 335 | 307 | 12 | 10 | ||||||||||||||||||||||||||||||||||||||
Funded Status at End of Year | $ | (72 | ) | $ | (23 | ) | $ | (69 | ) | $ | (64 | ) | ||||||||||||||||||||||||||||||
(1) | In 2015, TEP expects to contribute $23 million to the pension plans. | |||||||||||||||||||||||||||||||||||||||||
Schedule of Net Periodic Benefit Cost Not yet Recognized | The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented: | |||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree Benefits | |||||||||||||||||||||||||||||||||||||||||
Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Net Loss | $ | 118 | $ | 74 | $ | 11 | $ | 6 | ||||||||||||||||||||||||||||||||||
Prior Service Cost (Benefit) | 4 | — | (2 | ) | (2 | ) | ||||||||||||||||||||||||||||||||||||
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets | The accumulated benefit obligation aggregated for all pension plans is $365 million at December 31, 2014 and $297 million at December 31, 2013. | |||||||||||||||||||||||||||||||||||||||||
Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets: | ||||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Accumulated Benefit Obligation at End of Year | $ | 365 | $ | 13 | ||||||||||||||||||||||||||||||||||||||
Fair Value of Plan Assets at End of Year | 335 | — | ||||||||||||||||||||||||||||||||||||||||
Only the SERP, which is unfunded, had accumulated benefit obligations in excess of plan assets at December 31, 2013. Due to decreases in discount rates, and changes in mortality projections which reflect a longer life expectancy, all of our plans had accumulated benefit obligations in excess of plan assets at December 31, 2014. | ||||||||||||||||||||||||||||||||||||||||||
Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss) | The changes in plan assets and benefit obligations recognized as regulatory assets or in AOCI are as follows: | |||||||||||||||||||||||||||||||||||||||||
Pension Benefits | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||||||
Regulatory | QOCI | Regulatory | AOCI | Regulatory | AOCI | |||||||||||||||||||||||||||||||||||||
Asset | Asset | Asset | ||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Current Year Actuarial (Gain) Loss | $ | 49 | $ | 3 | $ | (42 | ) | $ | (1 | ) | $ | 28 | $ | 1 | ||||||||||||||||||||||||||||
Amortization of Actuarial Gain (Loss) | (3 | ) | — | (8 | ) | — | (7 | ) | — | |||||||||||||||||||||||||||||||||
Total Recognized (Gain) Loss | $ | 46 | $ | 3 | $ | (50 | ) | $ | (1 | ) | $ | 21 | $ | 1 | ||||||||||||||||||||||||||||
Other Retiree Benefits | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||||||
Regulatory | Regulatory | Regulatory | ||||||||||||||||||||||||||||||||||||||||
Asset | Asset | Asset | ||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Current Year Actuarial (Gain) Loss | $ | 5 | $ | (6 | ) | $ | 2 | |||||||||||||||||||||||||||||||||||
Schedule Of Weighted Average Assumptions Used To Determine Benefit Obligations At Year End Table | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree | |||||||||||||||||||||||||||||||||||||||||
Benefits | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31, | ||||||||||||||||||||||||||||||||||||||||||
Discount Rate | 4.1 - 4.2% | 5.0% - 5.1% | 3.9 | % | 4.7 | % | ||||||||||||||||||||||||||||||||||||
Rate of Compensation Increase | 3.00% | 3.00% | N/A | N/A | ||||||||||||||||||||||||||||||||||||||
Schedule Of Weighted Average Assumptions Used To Determine Net Periodic Benefit Cost Table | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | Other Retiree | |||||||||||||||||||||||||||||||||||||||||
Benefits | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||||
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||
Discount Rate | 5.0% - 5.1% | 4.1% - 4.1% | 4.9% - 5.0% | 4.7 | % | 3.8 | % | 4.7 | % | |||||||||||||||||||||||||||||||||
Rate of Compensation Increase | 3.00% | 3.00% | 3.00% | N/A | N/A | N/A | ||||||||||||||||||||||||||||||||||||
Expected Return on Plan Assets | 7.00% | 7.00% | 7.00% | 7 | % | 7 | % | 7 | % | |||||||||||||||||||||||||||||||||
Schedule of Health Care Cost Trend Rates | Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as net periodic benefit cost. The assumed health care cost trend rates follow: | |||||||||||||||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Health Care Cost Trend Rate Assumed for Next Year | 6.7 | % | 6.7 | % | ||||||||||||||||||||||||||||||||||||||
Ultimate Health Care Cost Trend Rate Assumed | 4.5 | % | 4.5 | % | ||||||||||||||||||||||||||||||||||||||
Year that the Rate Reaches the Ultimate Trend Rate | 2027 | 2027 | ||||||||||||||||||||||||||||||||||||||||
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates | Assumed health care cost trend rates significantly affect the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects on the December 31, 2014, amounts: | |||||||||||||||||||||||||||||||||||||||||
One Percentage | One Percentage | |||||||||||||||||||||||||||||||||||||||||
Point Increase | Point Decrease | |||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Effect on Total Service and Interest Cost Components | $ | 1 | $ | 1 | ||||||||||||||||||||||||||||||||||||||
Effect on Retiree Benefit Obligation | 7 | 6 | ||||||||||||||||||||||||||||||||||||||||
Schedule of Allocation of Plan Assets | We calculate the fair value of plan assets on December 31, the measurement date. Pension plan asset allocations, by asset category, on the measurement date were as follows: | |||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||||
Asset Category | ||||||||||||||||||||||||||||||||||||||||||
Equity Securities | 48 | % | 50 | % | ||||||||||||||||||||||||||||||||||||||
Fixed Income Securities | 43 | % | 40 | % | ||||||||||||||||||||||||||||||||||||||
Real Estate | 7 | % | 7 | % | ||||||||||||||||||||||||||||||||||||||
Other | 2 | % | 3 | % | ||||||||||||||||||||||||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||||||||||||||||||||||||
FV Measurements of Pension Plan Assets by FV Hierarchy | The following tables set forth the fair value measurements of pension plan assets by level within the fair value hierarchy: | |||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements of Pension Assets | ||||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||
Quoted Prices in | Significant Other | Significant | Total | |||||||||||||||||||||||||||||||||||||||
Active Markets | Observable Inputs | Unobservable | ||||||||||||||||||||||||||||||||||||||||
(Level 1) | (Level 2) | Inputs | ||||||||||||||||||||||||||||||||||||||||
(Level 3) | ||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Asset Category | ||||||||||||||||||||||||||||||||||||||||||
Cash Equivalents | $ | 1 | $ | — | $ | — | $ | 1 | ||||||||||||||||||||||||||||||||||
Equity Securities: | ||||||||||||||||||||||||||||||||||||||||||
United States Large Cap | — | 82 | — | 82 | ||||||||||||||||||||||||||||||||||||||
United States Small Cap | — | 17 | — | 17 | ||||||||||||||||||||||||||||||||||||||
Non-United States | — | 61 | — | 61 | ||||||||||||||||||||||||||||||||||||||
Fixed Income | — | 143 | — | 143 | ||||||||||||||||||||||||||||||||||||||
Real Estate | — | 8 | 16 | 24 | ||||||||||||||||||||||||||||||||||||||
Private Equity | — | — | 7 | 7 | ||||||||||||||||||||||||||||||||||||||
Total | $ | 1 | $ | 311 | $ | 23 | $ | 335 | ||||||||||||||||||||||||||||||||||
Fair Value Measurements of Pension Assets | ||||||||||||||||||||||||||||||||||||||||||
31-Dec-13 | ||||||||||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Asset Category | ||||||||||||||||||||||||||||||||||||||||||
Cash Equivalents | $ | 1 | $ | — | $ | — | $ | 1 | ||||||||||||||||||||||||||||||||||
Equity Securities: | ||||||||||||||||||||||||||||||||||||||||||
United States Large Cap | — | 76 | — | 76 | ||||||||||||||||||||||||||||||||||||||
United States Small Cap | — | 16 | — | 16 | ||||||||||||||||||||||||||||||||||||||
Non-United States | — | 62 | — | 62 | ||||||||||||||||||||||||||||||||||||||
Fixed Income | — | 124 | — | 124 | ||||||||||||||||||||||||||||||||||||||
Real Estate | — | 7 | 14 | 21 | ||||||||||||||||||||||||||||||||||||||
Private Equity | — | — | 7 | 7 | ||||||||||||||||||||||||||||||||||||||
Total | $ | 1 | $ | 285 | $ | 21 | $ | 307 | ||||||||||||||||||||||||||||||||||
Target Allocation Percentages for Plan Assets | The current target allocation percentages for the major asset categories of the plan as of December 31, 2014 follow. Each plan allows a variance of +/- 2% from these targets before funds are automatically rebalanced. | |||||||||||||||||||||||||||||||||||||||||
TEP Plans | VEBA Trust | |||||||||||||||||||||||||||||||||||||||||
Fixed Income | 41 | % | 38 | % | ||||||||||||||||||||||||||||||||||||||
United States Large Cap | 24 | % | 39 | % | ||||||||||||||||||||||||||||||||||||||
Non-United States Developed | 15 | % | 7 | % | ||||||||||||||||||||||||||||||||||||||
Real Estate | 8 | % | — | % | ||||||||||||||||||||||||||||||||||||||
United States Small Cap | 5 | % | 5 | % | ||||||||||||||||||||||||||||||||||||||
Non-United States Emerging | 5 | % | 9 | % | ||||||||||||||||||||||||||||||||||||||
Private Equity | 2 | % | — | % | ||||||||||||||||||||||||||||||||||||||
Cash/Treasury Bills | — | % | 2 | % | ||||||||||||||||||||||||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||||||||||||||||||||||||
Schedule of Expected Benefit Payments | TEP expects the following benefit payments to be made by the defined benefit pension plans and other retiree benefit plan, which reflect future service, as appropriate. | |||||||||||||||||||||||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | 2020-2024 | |||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||
Pension Benefits | $ | 17 | $ | 17 | $ | 19 | $ | 20 | $ | 21 | $ | 121 | ||||||||||||||||||||||||||||||
Other Retiree Benefits | 5 | 5 | 5 | 5 | 6 | 33 |
FAIR_VALUE_MEASUREMENTS_AND_DE1
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables) | 3 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||
Mar. 31, 2015 | Dec. 31, 2014 | |||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [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. | 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 | Net | Total | Level 1 | Level 2 | Level 3 | Counterparty | Net Amount | |||||||||||||||||||||||||||||||||||||||
Energy Contracts Not | Amount | Netting of | ||||||||||||||||||||||||||||||||||||||||||||||||
Offset on the Balance | Energy | |||||||||||||||||||||||||||||||||||||||||||||||||
Sheets(5) | Contracts Not | |||||||||||||||||||||||||||||||||||||||||||||||||
31-Mar-15 | Offset on the | |||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | Balance | |||||||||||||||||||||||||||||||||||||||||||||||||
Assets | Sheets(5) | |||||||||||||||||||||||||||||||||||||||||||||||||
Cash Equivalents(1) | $ | 50 | $ | 50 | $ | — | $ | — | $ | — | $ | 50 | December 31, 2014 | |||||||||||||||||||||||||||||||||||||
Restricted Cash(1) | 2 | 2 | — | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||||||
Rabbi Trust Investments(2) | 27 | — | 27 | — | — | 27 | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||||||
Energy Contracts—Regulatory Recovery(3) | 1 | — | — | 1 | (1 | ) | — | Assets | ||||||||||||||||||||||||||||||||||||||||||
Cash Equivalents(1) | $ | 15 | $ | 15 | $ | — | $ | — | $ | — | $ | 15 | ||||||||||||||||||||||||||||||||||||||
Total Assets | 80 | 52 | 27 | 1 | (1 | ) | 79 | Restricted Cash(1) | 2 | 2 | — | — | — | 2 | ||||||||||||||||||||||||||||||||||||
Rabbi Trust Investments(2) | 26 | — | 26 | — | — | 26 | ||||||||||||||||||||||||||||||||||||||||||||
Liabilities | Energy Contracts – Regulatory Recovery(3) | 1 | — | — | 1 | (1 | ) | — | ||||||||||||||||||||||||||||||||||||||||||
Energy Contracts—Regulatory Recovery(3) | (25 | ) | — | (13 | ) | (12 | ) | 1 | (24 | ) | Energy Contracts – No Regulatory Recovery(3) | 1 | — | — | 1 | (1 | ) | — | ||||||||||||||||||||||||||||||||
Energy Contracts—Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | |||||||||||||||||||||||||||||||||||||||||
Interest Rate Swaps(4) | (4 | ) | — | (4 | ) | — | — | (4 | ) | Total Assets | 45 | 17 | 26 | 2 | (2 | ) | 43 | |||||||||||||||||||||||||||||||||
Total Liabilities | (30 | ) | — | (17 | ) | (13 | ) | 1 | (29 | ) | Liabilities | |||||||||||||||||||||||||||||||||||||||
Energy Contracts – Regulatory Recovery(3) | (18 | ) | — | (9 | ) | (9 | ) | 1 | (17 | ) | ||||||||||||||||||||||||||||||||||||||||
Net Total Assets (Liabilities) | $ | 50 | $ | 52 | $ | 10 | $ | (12 | ) | $ | — | $ | 50 | Energy Contracts – No Regulatory Recovery(3) | (1 | ) | — | — | (1 | ) | 1 | — | ||||||||||||||||||||||||||||
Energy Contracts – Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | |||||||||||||||||||||||||||||||||||||||||
Interest Rate Swaps(4) | (5 | ) | — | (5 | ) | — | — | (5 | ) | |||||||||||||||||||||||||||||||||||||||||
Total Liabilities | (25 | ) | — | (14 | ) | (11 | ) | 2 | (23 | ) | ||||||||||||||||||||||||||||||||||||||||
Total | Level 1 | Level 2 | Level 3 | Counterparty Netting of | Net | |||||||||||||||||||||||||||||||||||||||||||||
Energy Contracts Not | Amount | Net Total Assets (Liabilities) | $ | 20 | $ | 17 | $ | 12 | $ | (9 | ) | — | $ | 20 | ||||||||||||||||||||||||||||||||||||
Offset on the Balance | ||||||||||||||||||||||||||||||||||||||||||||||||||
Sheets(5) | ||||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||||
Assets | Total | Level 1 | Level 2 | Level 3 | Counterparty | Net Amount | ||||||||||||||||||||||||||||||||||||||||||||
Cash Equivalents(1) | $ | 15 | $ | 15 | $ | — | $ | — | $ | — | $ | 15 | Netting of | |||||||||||||||||||||||||||||||||||||
Restricted Cash(1) | 2 | 2 | — | — | — | 2 | Energy | |||||||||||||||||||||||||||||||||||||||||||
Rabbi Trust Investments(2) | 26 | — | 26 | — | — | 26 | Contracts Not | |||||||||||||||||||||||||||||||||||||||||||
Energy Contracts—Regulatory Recovery(3) | 2 | — | — | 2 | (2 | ) | — | Offset on the | ||||||||||||||||||||||||||||||||||||||||||
Balance | ||||||||||||||||||||||||||||||||||||||||||||||||||
Total Assets | 45 | 17 | 26 | 2 | (2 | ) | 43 | Sheets(5) | ||||||||||||||||||||||||||||||||||||||||||
December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||
Energy Contracts—Regulatory Recovery(3) | (18 | ) | — | (9 | ) | (9 | ) | 1 | (17 | ) | Millions of Dollars | |||||||||||||||||||||||||||||||||||||||
Energy Contracts—No Regulatory Recovery(3) | (1 | ) | — | — | (1 | ) | 1 | — | Assets | |||||||||||||||||||||||||||||||||||||||||
Energy Contracts—Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | Cash Equivalents(1) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||||||||
Interest Rate Swaps(4) | (5 | ) | — | (5 | ) | — | — | (5 | ) | Restricted Cash(1) | 2 | 2 | — | — | — | 2 | ||||||||||||||||||||||||||||||||||
Rabbi Trust Investments(2) | 22 | — | 22 | — | — | 22 | ||||||||||||||||||||||||||||||||||||||||||||
Total Liabilities | (25 | ) | — | (14 | ) | (11 | ) | 2 | (23 | ) | Energy Contracts – No Regulatory Recovery(3) | 2 | — | 1 | 1 | (1 | ) | 1 | ||||||||||||||||||||||||||||||||
Net Total Assets (Liabilities) | $ | 20 | $ | 17 | $ | 12 | $ | (9 | ) | $ | — | $ | 20 | Total Assets | 26 | 2 | 23 | 1 | (1 | ) | 25 | |||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||
Energy Contracts – Regulatory Recovery(3) | (2 | ) | — | — | (2 | ) | 1 | (1 | ) | |||||||||||||||||||||||||||||||||||||||||
(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. | Energy Contracts – Cash Flow Hedge(3) | (1 | ) | — | — | (1 | ) | — | (1 | ) | |||||||||||||||||||||||||||||||||||||||
(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. | Interest Rate Swaps(4) | (7 | ) | — | (7 | ) | — | — | (7 | ) | |||||||||||||||||||||||||||||||||||||||
(3) | Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk, and, at December 31, 2014, a power sale option. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below. | |||||||||||||||||||||||||||||||||||||||||||||||||
(4) | An Interest Rate Swap valued using an income valuation approach, based on the 6-month London Interbank Offered Rate (LIBOR) is included in Derivative Instruments on the balance sheets. | Total Liabilities | 10 | — | (7 | ) | (3 | ) | 1 | (9 | ) | |||||||||||||||||||||||||||||||||||||||
(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. | |||||||||||||||||||||||||||||||||||||||||||||||||
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), forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk, and a power sale option (Level 3). 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 table: | 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: | ||||||||||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended March 31, | 2014 | 2013 | 2012 | |||||||||||||||||||||||||||||||||||||||||||||||
2015 | 2014 | Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | Unrealized Net Gain (Loss) Recorded in Regulatory (Assets) Liabilities | $ | (18 | ) | $ | — | $ | 6 | ||||||||||||||||||||||||||||||||||||||||||
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities | $ | (6 | ) | $ | 1 | |||||||||||||||||||||||||||||||||||||||||||||
Derivative Volumes | At March 31, 2015, we have energy contracts that will settle through the first quarter of 2018. The volumes associated with our energy contracts were as follows: | The volumes associated with our energy contracts were as follows: | ||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | December 31, 2013 | |||||||||||||||||||||||||||||||||||||||||||||||||
March 31, 2015 | December 31, 2014 | Power Contracts GWh | 2,604 | 779 | ||||||||||||||||||||||||||||||||||||||||||||||
Power Contracts GWh | 1,008 | 2,604 | Gas Contracts GBtu | 19,932 | 9,615 | |||||||||||||||||||||||||||||||||||||||||||||
Gas Contracts GBtu | 24,027 | 19,932 | ||||||||||||||||||||||||||||||||||||||||||||||||
Quantitative Information Regarding Unobservable Inputs | The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: | The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: | ||||||||||||||||||||||||||||||||||||||||||||||||
Valuation | Fair Value at | Range of | Fair Value at | Range of | ||||||||||||||||||||||||||||||||||||||||||||||
Approach | 31-Mar-15 | Unobservable | 31-Dec-14 | Unobservable Input | ||||||||||||||||||||||||||||||||||||||||||||||
Assets | Liabilities | Unobservable Inputs | Input | Valulation Approach | Assets | Liabilities | Unobservable Inputs | Minimum | Maximum | |||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||||
Forward Power Contracts | Market approach | $ | 1 | $ | (8 | ) | Market price per MWh | $ | 23.8 | $ | 37.7 | Forward Power Contracts | Market approach | $ | 1 | $ | (6 | ) | Market price per MWh | $22.35 | $39.05 | |||||||||||||||||||||||||||||
Gas Option Contracts | Option model | — | (5 | ) | Market price per MMbtu | $ | 2.34 | $ | 3.22 | Power Sale Option | Market approach | 1 | (1 | ) | Market price per MWh | $27.75 | $44.94 | |||||||||||||||||||||||||||||||||
Gas volatility | 24.15 | % | 39.91 | % | Market price per MWh | $2.88 | $4.02 | |||||||||||||||||||||||||||||||||||||||||||
Level 3 Energy Contracts | $ | 1 | $ | (13 | ) | Gas Option Contracts | Option model | — | (4 | ) | Market price per MWh | $2.72 | $3.26 | |||||||||||||||||||||||||||||||||||||
Valuation | Fair Value at | Range of | Gas volatility | 30.80% | 53.29% | |||||||||||||||||||||||||||||||||||||||||||||
Approach | December 31, 2014 | Unobservable | ||||||||||||||||||||||||||||||||||||||||||||||||
Assets | Liabilities | Unobservable Inputs | Input | Level 3 Energy Contracts | $ | 2 | $ | (11 | ) | |||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||||||||||||
Forward Power Contracts | Market approach | $ | 1 | $ | (6 | ) | Market price per MWh | $ | 22.35 | $ | 39.05 | |||||||||||||||||||||||||||||||||||||||
Power Sale Option | Market approach | 1 | (1 | ) | Market price per MWh | $ | 27.75 | $ | 44.94 | Fair Value at | Range of | |||||||||||||||||||||||||||||||||||||||
Market price per MMbtu | $ | 2.88 | $ | 4.02 | 31-Dec-13 | Unobservable Input | ||||||||||||||||||||||||||||||||||||||||||||
Valulation Approach | Assets | Liabilities | Unobservable Inputs | Minimum | Maximum | |||||||||||||||||||||||||||||||||||||||||||||
Gas Option Contracts | Option model | — | (4 | ) | Market price per MMbtu | $ | 2.72 | $ | 3.26 | |||||||||||||||||||||||||||||||||||||||||
Gas volatility | 30.8 | % | 53.29 | % | Forward Power Contracts | Market approach | $ | — | $ | (3 | ) | Market price per MWh | $27.00 | $48.25 | ||||||||||||||||||||||||||||||||||||
Gas Option Contracts | Option model | 1 | — | Market price per MWh | $3.88 | $4.32 | ||||||||||||||||||||||||||||||||||||||||||||
Level 3 Energy Contracts | $ | 2 | $ | (11 | ) | |||||||||||||||||||||||||||||||||||||||||||||
Gas volatility | 25.05% | 35.07% | ||||||||||||||||||||||||||||||||||||||||||||||||
Level 3 Energy Contracts | $ | 1 | $ | (3 | ) | |||||||||||||||||||||||||||||||||||||||||||||
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: | |||||||||||||||||||||||||||||||||||||||||||||||||
The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following: | ||||||||||||||||||||||||||||||||||||||||||||||||||
March 31, 2015 | December 31, 2014 | |||||||||||||||||||||||||||||||||||||||||||||||||
Fair | Carrying | Fair | Carrying | Fair | December 31, 2014 | December 31, 2013 | ||||||||||||||||||||||||||||||||||||||||||||
ValueHierarchy | Value | Value | Value | Value | Fair Value | Carrying | Fair | Carrying | Fair | |||||||||||||||||||||||||||||||||||||||||
Millions of Dollars | Hierachy | Value | Value | Value | Value | |||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt | Level 2 | $ | 1,541 | $ | 1,642 | $ | 1,372 | $ | 1,457 | Millions of Dollars | ||||||||||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Investment in Lease Equity(1) | Level 3 | N/A | N/A | $ | 36 | $ | 25 | |||||||||||||||||||||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt | Level 2 | 1,372 | 1,457 | 1,223 | 1,214 | |||||||||||||||||||||||||||||||||||||||||||||
(1) | Balance was transferred to Plant in Service in December 2014. |
NATURE_OF_OPERATIONS_AND_FINAN3
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Accounting Policies [Abstract] | |||||||||||||
AFUDC Rates | The average AFUDC rates on regulated construction expenditures are included in the table below: | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
Average AFUDC Rates | 7.3 | % | 7.38 | % | 7.22 | % | |||||||
Summary Of Average Annual Depreciation Rates For All Utility Plants | Below are the summarized average annual depreciation rates for all utility plant: | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
Average Annual Depreciation Rates | 2.99 | % | 3.16 | % | 3.22 | % |
REGULATORY_MATTERS_Tables
REGULATORY MATTERS (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Regulated Operations [Abstract] | |||||||||
Regulatory Assets and Liabilities | The following table summarizes regulatory assets and liabilities: | ||||||||
December 31, 2014 | December 31, 2013 | ||||||||
Millions of Dollars | |||||||||
Regulatory Assets-Current | |||||||||
Property Tax Deferrals(1) | $ | 21 | $ | 20 | |||||
PPFAC(2) | 19 | 4 | |||||||
Derivative Instruments (Note 10) | 15 | 1 | |||||||
LFCR and DSM(2) | 8 | 3 | |||||||
San Juan Mine Fire Cost Deferral(2) | 2 | 10 | |||||||
Other Current Regulatory Assets(3) | 4 | 5 | |||||||
Total Regulatory Assets—Current | 69 | 43 | |||||||
Regulatory Assets—Noncurrent | |||||||||
Pension and Other Retiree Benefits (Note 8) | 126 | 75 | |||||||
Income Taxes Recoverable Through Future Rates(4) | 31 | 22 | |||||||
PPFAC - Final Mine Reclamation and Retiree Health Care Costs(5) | 29 | 25 | |||||||
Springerville Lease Purchase Commitment Deferrals(6) | 16 | 2 | |||||||
Unamortized Loss on Reacquired Debt(7) | 6 | 7 | |||||||
LFCR(2) | $ | 4 | $ | — | |||||
Tucson to Nogales Transmission Line(8) | 4 | 5 | |||||||
Other Regulatory Assets(3) | 7 | 5 | |||||||
Total Regulatory Assets—Noncurrent | 223 | 141 | |||||||
Regulatory Liabilities—Current | |||||||||
RES(2) | (28 | ) | (22 | ) | |||||
DSM(2) | (6 | ) | — | ||||||
Fortis Merger Customer Credits(9) | (5 | ) | — | ||||||
Other Current Regulatory Liabilities | — | (2 | ) | ||||||
Total Regulatory Liabilities—Current | (39 | ) | (24 | ) | |||||
Regulatory Liabilities—Noncurrent | |||||||||
Net Cost of Removal for Interim Retirements(10) | (265 | ) | (254 | ) | |||||
Deferred Investment Tax Credits(11) | (25 | ) | (4 | ) | |||||
Income Taxes Payable through Future Rates(4) | (20 | ) | (5 | ) | |||||
Fortis Merger Customer Credits(9) | (11 | ) | — | ||||||
Total Regulatory Liabilities—Noncurrent | (321 | ) | (263 | ) | |||||
Total Net Regulatory Assets (Liabilities) | $ | (68 | ) | $ | (103 | ) | |||
Regulatory assets are either being collected in Retail Rates or are expected to be collected through Retail Rates in a future period. With the exception of interest earned on under-recovered PPFAC costs, we do not earn a return on regulatory assets. Regulatory liabilities represent items that we either expect to pay to customers through billing reductions in future periods or plan to use for the purpose for which they were collected from customers. | |||||||||
-1 | Property Taxes are recovered over approximately a six months period as costs are paid, rather than as costs are accrued. | ||||||||
-2 | See Cost Recovery Mechanisms discussed above. | ||||||||
-3 | Other regulatory assets include self-insured medical costs and short-term disability costs recovered on a pay-as-you-go or cash basis; San Juan Coal Contract Amendment costs (recovery through 2017); rate case costs (recovery over three years); and environmental compliance costs (recovery over one year). | ||||||||
-4 | Income Taxes Recoverable through Future Revenues are amortized over the life of the assets. See Note 1 of Notes to Consolidated Financial Statements. | ||||||||
-5 | Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years. | ||||||||
-6 | TEP deferred the increase in lease interest expense relating to the purchase commitments for Springerville Unit 1 and the Springerville Coal Handling Facilities to a regulatory asset because TEP believes the full purchase price is recoverable in rate base. See Note 5 of Notes to Consolidated Financial Statements. | ||||||||
-7 | In accordance with FERC guidelines, when TEP refinances its long-term debt, TEP defers and amortizes losses on reacquired debt over the life of the debt agreement. | ||||||||
-8 | TEP will request recovery from FERC for the costs incurred to develop a high-voltage transmission line from Tucson to Nogales; the project is not going forward. See Note 6 of Notes to Consolidated Financial Statements | ||||||||
-9 | Fortis Merger Customer Credits represent credits to be applied to customers’ bills according to the Merger Agreement. These credits will be applied to customer bills each year, October through March for a period of five years. See Note 1 of Notes to Consolidated Financial Statements. | ||||||||
-10 | Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future. | ||||||||
-11 | The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset. |
UTILITY_PLANT_AND_JOINTLYOWNED1
UTILITY PLANT AND JOINTLY-OWNED FACILITIES (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Text Block [Abstract] | |||||||||||||||||||
Public Utility Property, Plant, and Equipment | The following table shows Utility Plant in Service by major class: | ||||||||||||||||||
December 31, | |||||||||||||||||||
2014 | 2013 | ||||||||||||||||||
Millions of Dollars | |||||||||||||||||||
Plant in Service: | |||||||||||||||||||
Electric Generation Plant | $ | 2,388 | $ | 1,889 | |||||||||||||||
Electric Transmission Plant | 898 | 825 | |||||||||||||||||
Electric Distribution Plant | 1,398 | 1,298 | |||||||||||||||||
General Plant | 338 | 312 | |||||||||||||||||
Intangible Plant - Software Costs(1) (2) | 149 | 141 | |||||||||||||||||
Electric Plant Held for Future Use | 4 | 3 | |||||||||||||||||
Total Plant in Service | $ | 5,175 | $ | 4,468 | |||||||||||||||
Utility Plant under Capital Leases(3) | $ | 667 | $ | 638 | |||||||||||||||
-1 | Unamortized computer software costs were $31 million as of December 31, 2014, and $39 million as of December 31, 2013. | ||||||||||||||||||
-2 | The amortization of computer software costs was $17 million in 2014, $14 million in 2013, and $13 million in 2012. | ||||||||||||||||||
-3 | In 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5 of Notes to Consolidated Financial Statements. | ||||||||||||||||||
Amount Of Lease Expense Incurred Related Capital Leases | The following table shows the amount of lease expense incurred for generation-related capital leases: | ||||||||||||||||||
Year Ended December 31, | |||||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||||
Millions of Dollars | |||||||||||||||||||
Lease Expense: | |||||||||||||||||||
Interest Expense—Included in: | |||||||||||||||||||
Capital Leases | $ | 10 | $ | 25 | $ | 34 | |||||||||||||
Operating Expenses—Fuel | 1 | 2 | 3 | ||||||||||||||||
Amortization of Capital Lease Assets—Included in: | |||||||||||||||||||
Operating Expenses—Fuel | 6 | 5 | 4 | ||||||||||||||||
Operating Expenses—Amortization | 16 | 15 | 14 | ||||||||||||||||
Total Lease Expense: | $ | 33 | $ | 47 | $ | 55 | |||||||||||||
Depreciable Lives Of Utility Plant In Service | Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available at December 31, 2014, were as follows: | ||||||||||||||||||
December 31, 2014 | |||||||||||||||||||
Annual Depreciation | Average Remaining Life | ||||||||||||||||||
Rate (3) | in Years | ||||||||||||||||||
Major Class of Utility Plant in Service: | |||||||||||||||||||
Electric Generation Plant (1) | 3.31 | % | 22 | ||||||||||||||||
Electric Transmission Plant | 1.48 | % | 32 | ||||||||||||||||
Electric Distribution Plant (1) | 2.08 | % | 35 | ||||||||||||||||
General Plant (1) | 5.48 | % | 11 | ||||||||||||||||
Intangible Plant (2) | Various | Various | |||||||||||||||||
(1) | In June 2013, the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 2 of Notes to Consolidated Financial Statements. | ||||||||||||||||||
(2) | The majority of TEP’s investment in intangible plant represents computer software, which is being amortized over its expected useful life of three to five years for smaller application software. For large enterprise software, we use the remaining life depreciation method. At December 31, 2014, remaining lives ranged from one to six years. | ||||||||||||||||||
(3) | The depreciation rates represent a composite of the depreciation rates of assets within each major class of utility plant. | ||||||||||||||||||
Schedule of Jointly Owned Utility Plants | At December 31, 2014, TEP was a participant in jointly-owned generating stations and transmission systems as follows: | ||||||||||||||||||
Ownership | Plaint in Service | Construction | Accumulated | Net Book | |||||||||||||||
Percentage | Work in | Depreciation | Value | ||||||||||||||||
Progress | |||||||||||||||||||
Millions of Dollars | |||||||||||||||||||
San Juan Units 1 and 2 | 50.00% | $ | 453 | $ | 8 | $ | 242 | $ | 219 | ||||||||||
Navajo Units 1, 2, and 3 | 7.50% | 153 | 1 | 112 | 42 | ||||||||||||||
Four Corners Units 4 and 5 | 7.00% | 104 | 3 | 77 | 30 | ||||||||||||||
Luna Energy Facility | 33.30% | 55 | — | 2 | 53 | ||||||||||||||
Gila River Unit 3 | 75.00% | 186 | — | 54 | 132 | ||||||||||||||
Gila River Common Facilities | 18.75% | 42 | — | 11 | 31 | ||||||||||||||
Transmission Facilities | Various | 371 | 21 | 193 | 199 | ||||||||||||||
Total | $ | 1,364 | $ | 33 | $ | 691 | $ | 706 | |||||||||||
Schedule of Asset Retirement Obligations | The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the balance sheets: | ||||||||||||||||||
December 31, | |||||||||||||||||||
2014 | 2013 | ||||||||||||||||||
Millions of Dollars | |||||||||||||||||||
Beginning Balance | $ | 22 | $ | 14 | |||||||||||||||
Liabilities Incurred | 5 | — | |||||||||||||||||
Accretion Expense or Regulatory Deferral | 1 | 1 | |||||||||||||||||
Revisions to the Present Value of Estimated Cash Flows(1) | — | 7 | |||||||||||||||||
Ending Balance | $ | 28 | $ | 22 | |||||||||||||||
-1 | Primarily related to changes in expected retirement dates of generating facilities. |
DEBT_AND_CAPITAL_LEASE_OBLIGAT1
DEBT AND CAPITAL LEASE OBLIGATIONS (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Debt Disclosure [Abstract] | |||||||||||||
Interest Rates on TEP's Variable Rate | The following table shows interest rates (exclusive of LOC and remarketing fees) on TEP’s weekly variable rate bonds, which are reset weekly by its remarketing agents: | ||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Interest Rates on Bonds | |||||||||||||
Average Interest Rate | 0.08% | 0.10% | 0.17% | ||||||||||
Range of Average Weekly Rates | .05% - 0.13% | 0.06% - 0.25% | 0.06% - 0.26% | ||||||||||
Effect Of Fixing Interest Rates On Amortizing Principal Balances Of Swaps | The swap has the effect of fixing the interest rates on the amortizing principal balances as follows: | ||||||||||||
Fixed Rate | LIBOR Spread | ||||||||||||
Lease Debt Outstanding at December 31, 2014 | |||||||||||||
Notional Amount $32 million - Effective Date June 2006 | 5.77% | 1.75% | |||||||||||
Maturities of Long-term Debt | Long-term debt, including term loan payments, revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates: | ||||||||||||
Long-Term Debt | Capital Lease | Total | |||||||||||
Maturities (1) | Obligations | ||||||||||||
Millions of Dollars | |||||||||||||
2015 | $ | — | $ | 188 | $ | 188 | |||||||
2016 | 79 | 16 | 95 | ||||||||||
2017 | — | 18 | 18 | ||||||||||
2018 | 100 | 11 | 111 | ||||||||||
2019 | 37 | 12 | 49 | ||||||||||
Total 2015 - 2019 | 216 | 245 | 461 | ||||||||||
Thereafter | 1,159 | 18 | 1,177 | ||||||||||
Less: Imputed Interest | — | (20 | ) | (20 | ) | ||||||||
Total | $ | 1,375 | $ | 243 | $ | 1,618 | |||||||
(1) | $115 million of TEP’s variable rate bonds are backed by LOCs issued pursuant to the 2010 Credit Agreement, which expires in November 2016, and the TEP 2010 Reimbursement Agreement, which expires in December 2019. Although the variable rate bonds mature between 2022 and 2032, the above table reflects a redemption or repurchase of such bonds in 2016 and 2019 as though the LOCs terminate without replacement upon expiration of the 2010 Credit Agreement and the 2010 Reimbursement Agreement. TEP’s 2013 tax-exempt variable rate IDRBs, which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in 2018. The repayment of TEP Unsecured Notes is not reduced by the remaining $2 million original issue discount. |
PURCHASE_OF_GASFIRED_GENERATIO1
PURCHASE OF GAS-FIRED GENERATION FACILITY (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Commitments and Contingencies Disclosure [Abstract] | |||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | The following table summarizes the assets acquired and liabilities assumed as of the acquisition date: | ||||
Millions of Dollars | |||||
Utility Plant - Net | $ | 163 | |||
Materials and Supplies | 2 | ||||
ARO Obligation Assumed(1) | (1 | ) | |||
Total Purchase Price | $ | 164 | |||
-1 | The ARO obligation was recorded at net present value in Deferred Credits and Other Liabilities - Other on TEP’s balance sheet. |
SUPPLEMENTAL_CASH_FLOW_INFORMA1
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Supplemental Cash Flow Elements [Abstract] | |||||||||||||
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | CASH PAYMENTS | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Thousands of Dollars | |||||||||||||
Interest Paid, Net of Amounts Capitalized | $ | (82,653 | ) | $ | (52,589 | ) | $ | (52,125 | ) | ||||
Income Taxes Paid | — | — | (1,796 | ) | |||||||||
Supplemental Noncash Investing And Financing Activities Table | Other non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows: | ||||||||||||
Years Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Thousands of Dollars | |||||||||||||
(Decrease)/Increase to Utility Plant Accruals(1) | $ | 5,138 | $ | 4,995 | $ | 4,813 | |||||||
Net Cost of Removal of Interim Retirements(2) | 12,128 | 25,182 | 35,983 | ||||||||||
Capital Lease Obligations(3) | 1,107 | 9,039 | 11,967 | ||||||||||
Asset Retirement Obligations(4) | 4,117 | 8,064 | 789 | ||||||||||
(1) | The non-cash additions to Utility Plant represent accruals for capital expenditures. | ||||||||||||
(2) | The non-cash net cost of removal of interim retirements represents an accrual for future asset retirement obligations that does not impact earnings. | ||||||||||||
(3) | The non-cash change in capital lease obligations represents interest accrued for accounting purposes in excess of interest payments. | ||||||||||||
(4) | The non-cash additions to asset retirement obligations and related capitalized assets represent revision of estimated asset retirement cost due to changes in timing and amount of expected future asset retirement obligations. |
INCOME_TAXES_Tables
INCOME TAXES (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Income Tax Disclosure [Abstract] | |||||||||||||
Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate | Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Millions of Dollars | |||||||||||||
Federal Income Tax Expenses at Statutory Rate | $ | 56 | $ | 52 | $ | 37 | |||||||
State Income Tax Espense, Net of Federal Deduction | 7 | 7 | 5 | ||||||||||
Federal/State Tax Credits | (5 | ) | (2 | ) | (1 | ) | |||||||
Allowance for Equity Funds Used During Construction | (2 | ) | (1 | ) | (1 | ) | |||||||
Deferred Tax Asset Valuation Allowance | $ | — | 2 | — | |||||||||
Investment Tax Credit Basis Adjustment – Creation of Regulatory Asset | — | (11 | ) | — | |||||||||
Other | 2 | 1 | (1 | ) | |||||||||
Total Federal and State Income Tax Expense | $ | 58 | $ | 48 | $ | 39 | |||||||
Schedule of Income Tax Reconciliation Table | Income tax expense included in the income statements consists of the following: | ||||||||||||
Year Ended December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Millions of Dollars | |||||||||||||
Current Tax Expense (Benefit): | |||||||||||||
Federal | $ | (1 | ) | $ | (8 | ) | $ | (4 | ) | ||||
State | — | (2 | ) | (2 | ) | ||||||||
Total Current Tax Expense (Benefit) | (1 | ) | (10 | ) | (6 | ) | |||||||
Federal | $ | 54 | 47 | 38 | |||||||||
Federal Investment Tax Credits | (4 | ) | (1 | ) | — | ||||||||
State | 9 | 12 | 7 | ||||||||||
Total Deferred Tax Expense (Benefit) | 59 | 58 | 45 | ||||||||||
Total Federal and State Income Tax Expense | $ | 58 | $ | 48 | $ | 39 | |||||||
Schedule of Deferred Tax Assets and Liabilities | The significant components of deferred income tax assets and liabilities consist of the following: | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Millions of Dollars | |||||||||||||
Gross Deferred Income Tax Assets: | |||||||||||||
Capital Lease Obligations | $ | 96 | $ | 127 | |||||||||
Net Operating Loss Carryforwards | 187 | 104 | |||||||||||
Customer Advances and Contributions in Aid of Construction | 19 | 19 | |||||||||||
Alternative Minimum Tax Credit | 24 | 24 | |||||||||||
Accrued Postretirement Benefits | 23 | 23 | |||||||||||
Emission Allowance Inventory | 10 | 10 | |||||||||||
Investment Tax Credit Carryforward | 31 | 6 | |||||||||||
Other | 54 | 38 | |||||||||||
Total Gross Deferred Income Tax Assets | 444 | 351 | |||||||||||
Deferred Tax Assets Valuation Allowance | (2 | ) | (2 | ) | |||||||||
Gross Defined Income Tax Liabilities: | |||||||||||||
Plant - Net | (699 | ) | (615 | ) | |||||||||
Capital Lease Assets - Net | (74 | ) | (47 | ) | |||||||||
Pensions | (27 | ) | (22 | ) | |||||||||
PPFAC | (8 | ) | (2 | ) | |||||||||
Other | (24 | ) | (20 | ) | |||||||||
Total Gross Deferred Income Tax Liabilities | (832 | ) | (706 | ) | |||||||||
Net Deferred Income Tax Liabilities | $ | (390 | ) | $ | 357 | ) | |||||||
Summary of Deferred Tax Liability Not Recognized | The net deferred income tax liability on the balance sheets is as follows: | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Millions of Dollars | |||||||||||||
Deferred Income Taxes – Current Assets | $ | 102 | $ | 71 | |||||||||
Deferred Income Taxes – Noncurrent Liabilities | $ | (492 | ) | $ | (428 | ) | |||||||
Net Deferred Income Tax Liability | $ | (390 | ) | $ | (357 | ) | |||||||
Summary of Details of Tax Carryforwards Table | As of December 31, 2014, TEP had the following carryforward amounts: | ||||||||||||
Amount | Expiring Year | ||||||||||||
Millions of Dollars | |||||||||||||
Federal Net Operating Loss | $ | 507 | 2031-34 | ||||||||||
State Net Operating Loss | 237 | 2016-34 | |||||||||||
State Credits | 8 | 2016-19 | |||||||||||
Alternative Minimum Tax Credit | 24 | None | |||||||||||
Investment Tax Credits | 31 | 2032-34 | |||||||||||
Summary of Income Tax Contingencies | A reconciliation of the beginning and ending balances of unrecognized tax benefits follows: | ||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Millions of Dollars | |||||||||||||
Unrecognized Tax Benefits, Beginning of Year | $ | 2 | $ | 23 | |||||||||
Additions Based on Tax Positions Taken in the Current Year | 2 | 1 | |||||||||||
Reductions of Positions from Prior Year Based on Tax Authority Ruling | — | (22 | ) | ||||||||||
Unrecognized Tax Benefits, End of Year | $ | 4 | $ | 2 | |||||||||
QUARTERLY_FINANCIAL_DATA_UNAUD1
QUARTERLY FINANCIAL DATA (UNAUDITED (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||
Schedule of Quarterly Financial Information | Accordingly, comparisons among quarters of a year may not represent overall trends and changes in operations. | ||||||||||||||||
First | Second | Third | Fourth | ||||||||||||||
Thousands of Dollars | |||||||||||||||||
2014 | |||||||||||||||||
Operating Revenue | $ | 255,513 | $ | 321,618 | $ | 387,411 | $ | 305,359 | |||||||||
Operating Income | 31,999 | 79,653 | 84,898 | 34,138 | |||||||||||||
Net Income | 9,172 | 38,725 | 39,644 | 14,797 | |||||||||||||
2013 | |||||||||||||||||
Operating Revenue | $ | 247,751 | $ | 304,263 | $ | 371,239 | $ | 273,437 | |||||||||
Operating Income | 22,747 | 53,433 | 123,177 | 31,014 | |||||||||||||
Net Income | 1,478 | 30,787 | 64,167 | 4,910 | |||||||||||||
NATURE_OF_OPERATIONS_AND_FINAN4
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION - Nature of Operations (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
sqmi | sqmi | ||
Customer | Customer | ||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Entity Number Of Customers | 417,000 | 415,000 | |
Area In Which Subsidiary Generates Transmits And Distributes Electricity To Retail Electric Customers | 1,155 | 1,155 | |
Restricted Cash and Cash Equivalents, Noncurrent | $2 | $2 |
REGULATORY_MATTERS_COST_RECOVE
REGULATORY MATTERS COST RECOVERY MECHANISMS (Detail) (USD $) | 0 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | 43 Months Ended | |||
1-May-14 | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2015 | Mar. 31, 2015 | |
Schedule of Regulatory Cost Recovery Mechanisms [Line Items] | ||||||||
Purchased Power And Fuel Adjustment Clause Rate | 0.005 | 0.0014 | ||||||
Mine Fire Cost Deferral | $10,000,000 | $2,000,000 | $10,000,000 | $10,000,000 | $10,000,000 | |||
Environmental Compliance Adjustor Rate Effective On May 1 2014 | 0.000049 | 0.000049 | ||||||
Revenue Recognized Under Environmental Compliance Adjustor Less Than | 500,000 | |||||||
Energy Efficiency Performance Incentive | 3,000,000 | 2,000,000 | ||||||
Cap on increase in lost fixed cost recovery rate | 1.00% | 1.00% | ||||||
Revenue Recognized Under Lost Fixed Cost Recovery Mechanism | 3,000,000 | 5,000,000 | 11,327,000 | 2,171,000 | 0 | |||
Lost Fixed Cost Recovery Approved | 5,000,000 | |||||||
Effective April 2015 Through March 2016 [Member] | ||||||||
Schedule of Regulatory Cost Recovery Mechanisms [Line Items] | ||||||||
Purchased Power And Fuel Adjustment Clause Rate | 0.0068 | |||||||
Fire [Member] | ||||||||
Schedule of Regulatory Cost Recovery Mechanisms [Line Items] | ||||||||
Insurance Proceeds Received to Date | $8,000,000 |
REGULATORY_MATTERS_REGULATORY_
REGULATORY MATTERS REGULATORY ASSETS (Detail) (Springerville Unit 1, USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Jan. 31, 2015 |
Jointly Owned Utility Plant Interests [Line Items] | ||
Increase (Decrease) in Other Regulatory Assets | $25 | |
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Amortization Period | 10 years | |
Completion of Purchase of Equity Interest [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Jointly Owned Utility Plant, Proportionate Ownership Share | 49.50% |
RELATED_PARTY_TRANSACTIONS_Rel
RELATED PARTY TRANSACTIONS Related Party Transactions Other Than Share-Based Compensation (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Receivable from Related Parties | $5 | $5 | $6 | ||
Payable to Related Parties | 4 | 3 | 9 | ||
Intercompany Allocation Parent to Subsidiary | 81.00% | 81.00% | |||
Management fee | 1 | ||||
Merger Related Costs | 1 | ||||
Tucson Electric Power Company To Uns Electric [Member] | |||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Wholesale Sales | 2 | 0 | 4 | 1 | 2 |
Control Area Services | 0 | 1 | 3 | 4 | 3 |
TEP to UNS Energy Affiliates [Member] | |||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Common Costs | 3 | 3 | 13 | 12 | 12 |
Southwest Energy Solutions, Inc. to TEP [Member] | |||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Supplemental Workforce | 4 | 4 | 16 | 16 | 17 |
UNS Energy to TEP [Member] | |||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Corporate Services | 1 | 1 | 14 | 5 | 2 |
Uns Electric To Tucson Electric Power Company [Member] | |||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Wholesale Purchases from Related Parties | 4 | 2 | 1 | ||
UNS Energy Affiliates to TEP [Member] | |||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Corporate Services | 1 | 1 | 1 | ||
UNS Electric [Member] | |||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Receivable from Related Parties | 4 | 4 | 3 | ||
Payable to Related Parties | 0 | 1 | 0 | ||
Uns Gas [Member] | |||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Receivable from Related Parties | 1 | 1 | 2 | ||
Uns Energy Corporation [Member] | |||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Receivable from Related Parties | 0 | 1 | |||
Payable to Related Parties | 1 | 0 | 7 | ||
Southwest Energy Solutions, Inc. [Member] | |||||
Related Party Transaction, Due from (to) Related Parties [Abstract] | |||||
Payable to Related Parties | $3 | $2 | $2 |
RELATED_PARTY_TRANSACTIONS_Sha
RELATED PARTY TRANSACTIONS Share-Based Compensation Expense (Detail) (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Related Party Transactions [Abstract] | ||
Allocated Share-based Compensation Expense Less Than | $1 | $1 |
DEBT_AND_CAPITAL_LEASE_OBLIGAT2
DEBT AND CAPITAL LEASE OBLIGATIONS (Capital Leases) (Detail) (USD $) | 1 Months Ended | ||||||
Apr. 30, 2014 | Apr. 30, 2015 | Dec. 31, 2014 | Mar. 31, 2015 | Jun. 30, 2015 | Apr. 30, 2016 | Jan. 31, 2015 | |
MW | MW | ||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||
Generating Capacity Purchased, in MWs | 192 | ||||||
Springerville Coal Handling Facilities Lease [Member] | |||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||
Fixed price to acquire leased interest in facilities | $120,000,000 | ||||||
Springerville Coal Handling Facilities Lease [Member] | Subsequent Event [Member] | |||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 100.00% | ||||||
Jointly Owned Utility Plant Proportionate Ownership Share, Purchased | 86.70% | ||||||
Fixed price to acquire leased interest in facilities | 120,000,000 | ||||||
Springerville Coal Handling Facilities Lease [Member] | SRP [Member] | |||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||
Sales Price of Leased Interest In Facilities | 24,000,000 | ||||||
Recorded Amounts of Third Party Commitments | 0 | ||||||
Springerville Coal Handling Facilities Lease [Member] | SRP [Member] | Subsequent Event [Member] | |||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||
Sales Price of Leased Interest In Facilities | 24,000,000 | ||||||
Springerville Coal Handling Facilities Lease [Member] | Tri-State [Member] | |||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||
Sales Price of Leased Interest In Facilities | 24,000,000 | ||||||
Recorded Amounts of Third Party Commitments | 0 | ||||||
Springerville Coal Handling Facilities Lease [Member] | Tri-State [Member] | Subsequent Event [Member] | |||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||
Sales Price of Leased Interest In Facilities | 24,000,000 | ||||||
Springerville Unit 1 | Additional Purchase of Equity Interest [Member] | |||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 24.80% | ||||||
Lease arrangement, fair market value purchase price | $46,000,000 | ||||||
Generating Capacity Purchased, in MWs | 96 | ||||||
Springerville Unit 1 | Completion of Purchase of Equity Interest [Member] | |||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 49.50% | ||||||
Generating Capacity Purchased, in MWs | 192 |
DEBT_AND_CAPITAL_LEASE_OBLIGAT3
DEBT AND CAPITAL LEASE OBLIGATIONS (Debt) (Detail) (USD $) | 3 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | |||||||
Mar. 31, 2015 | Apr. 30, 2013 | Dec. 31, 2012 | Jan. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Sep. 30, 2012 | Feb. 27, 2015 | 4-May-15 | Apr. 23, 2015 | |
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Letters of Credit Outstanding, Amount | $1,000,000 | ||||||||||
Short-term Debt [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Extinguishment of Debt, Amount | 215,000,000 | ||||||||||
T E P 2010 Credit Agreement [Member] | Revolving Credit Facility [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||||||||
Interest rate in addition to alternate base rate for alternate base rate loans | 0.00% | ||||||||||
T E P 2014 Credit Agreement [Member] | Domestic Line of Credit [Member] | Domestic Line of Credit [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Extinguishment of Debt, Amount | 70,000,000 | ||||||||||
T E P 2014 Credit Agreement [Member] | Loans Payable [Member] | Loans Payable [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Extinguishment of Debt, Amount | 130,000,000 | ||||||||||
T E P 2010 Reimbursement Agreement [Member] | Letter of Credit [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases | 37,000,000 | ||||||||||
Line of Credit Facility, Interest Rate at Period End | 0.75% | ||||||||||
Unsecured Debt [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Fixed interest rate of long-term debt | 6.38% | 5.75% | 5.00% | 4.00% | 3.85% | ||||||
Extinguishment of Debt, Amount | 91,000,000 | 193,000,000 | |||||||||
Unsecured Debt [Member] | Unsecured Debts 5.75 due September 2029 [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Repurchased Debt Amount | 130,000,000 | ||||||||||
Fixed interest rate of long-term debt | 5.75% | ||||||||||
Debt Instrument, Maturity Date | 1-Sep-29 | ||||||||||
Unsecured Debt [Member] | Unsecured Debts 3.05 due March 2025 [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Fixed interest rate of long-term debt | 3.05% | ||||||||||
Debt Instrument, Maturity Date | 15-Mar-25 | ||||||||||
Long-term Debt, Gross | 300,000,000 | ||||||||||
Debt Instrument, Call Date, Latest | 15-Dec-24 | ||||||||||
Debt Instrument, Frequency of Periodic Payment | Semi-annually | ||||||||||
Unsecured Debt [Member] | Subsequent Event [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Extinguishment of Debt, Amount | 130,000,000 | ||||||||||
Revolving Credit Facility [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Line of Credit Facility, Remaining Borrowing Capacity | 185,000,000 | ||||||||||
Revolving Credit Facility [Member] | T E P 2010 Credit Agreement [Member] | Revolving Credit Facility [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Line of Credit Facility, Remaining Borrowing Capacity | 200,000,000 | ||||||||||
Revolving Credit Facility [Member] | T E P 2010 Credit Agreement [Member] | Revolving Credit Facility [Member] | Domestic Line of Credit [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Extinguishment of Debt, Amount | 15,000,000 | ||||||||||
Revolving Credit Facility [Member] | T E P 2014 Credit Agreement [Member] | Domestic Line of Credit [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Line of Credit Facility, Remaining Borrowing Capacity | 70,000,000 | ||||||||||
Revolving Credit Facility [Member] | Subsequent Event [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Line of Credit Facility, Remaining Borrowing Capacity | 170,000,000 | ||||||||||
Revolving Credit Facility [Member] | Subsequent Event [Member] | T E P 2010 Credit Agreement [Member] | Revolving Credit Facility [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Line of Credit Facility, Remaining Borrowing Capacity | 142,000,000 | ||||||||||
Revolving Credit Facility [Member] | Subsequent Event [Member] | T E P 2014 Credit Agreement [Member] | Domestic Line of Credit [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Line of Credit Facility, Remaining Borrowing Capacity | 0 | ||||||||||
Letter of Credit [Member] | T E P 2010 Credit Agreement [Member] | Letter of Credit [Member] | |||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||||||||
Letters of Credit Outstanding, Amount | $82,000,000 |
COMMITMENTS_CONTINGENCIES_AND_2
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS COMMITMENTS (Detail) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2015 |
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2015 | $31 | |||
2016 | 146 | 13 | ||
2017 | 137 | 2 | ||
2018 | 110 | 2 | ||
2019 | 108 | 2 | ||
Thereafter | 1,024 | 47 | ||
Total | 1,685 | 97 | ||
2015 | 160 | |||
Duration of contract obligation in year | 20 years | |||
Rent expense | 3 | 2 | 2 | |
Fuel, Including Transportation | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2015 | 1 | |||
2016 | 78 | 2 | ||
2017 | 76 | 2 | ||
2018 | 49 | 2 | ||
2019 | 49 | 2 | ||
Thereafter | 285 | 47 | ||
Total | 613 | 56 | ||
2015 | 76 | |||
Purchased Power | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2015 | 30 | |||
2016 | 7 | 11 | ||
2017 | 0 | 0 | ||
2018 | 0 | 0 | ||
2019 | 0 | 0 | ||
Thereafter | 0 | 0 | ||
Total | 29 | 41 | ||
2015 | 22 | |||
Transmission Facilities [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2016 | 6 | |||
2017 | 6 | |||
2018 | 6 | |||
2019 | 4 | |||
Thereafter | 16 | |||
Total | 44 | |||
2015 | 6 | |||
Renewable Power Purchase Agreements [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2016 | 45 | |||
2017 | 45 | |||
2018 | 45 | |||
2019 | 44 | |||
Thereafter | 565 | |||
Total | 789 | |||
2015 | 45 | |||
Percentage of purchase power obligations | 100.00% | |||
RES Performance Based Incentives Minimum Commitment [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2016 | 8 | |||
2017 | 8 | |||
2018 | 8 | |||
2019 | 8 | |||
Thereafter | 76 | |||
Total | 116 | |||
2015 | 8 | |||
Land Easements and Rights-of-Way [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2016 | 1 | |||
2017 | 1 | |||
2018 | 1 | |||
2019 | 2 | |||
Thereafter | 77 | |||
Total | 84 | |||
2015 | 2 | |||
Operating Lease [Member] | ||||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||||
2016 | 1 | |||
2017 | 1 | |||
2018 | 1 | |||
2019 | 1 | |||
Thereafter | 5 | |||
Total | 10 | |||
2015 | $1 |
COMMITMENTS_CONTINGENCIES_AND_3
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS CONTINGENCIES (Detail) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2012 | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | 4-May-15 | |
Commitments And Contingencies [Line Items] | |||||
TEP's share of reclamation costs at expiration dates of the coal supply agreements | $52,000,000 | $49,000,000 | |||
TEP's recorded obligations for final mine reclamation costs | 23,000,000 | 22,000,000 | 18,000,000 | ||
Share of Defaulting Participants' Payment | 0 | ||||
Tucson To Nogales [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Transmission line from Tucson to Nogales | 60 | 60 | |||
Transmission Line, in KV | 345 | 345 | |||
Asset Impairment Charges | 5,000,000 | ||||
Regulatory Assets | 5,000,000 | 5,000,000 | |||
Springerville Unit 1 Third Party Owner Allegation [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Loss Contingency, Damages Sought, Value | 71,000,000 | 71,000,000 | |||
San Juan [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Percentage of ownership in generating station | 50.00% | 50.00% | |||
Percentage Of Ownership In Generating Units | 20.00% | 20.00% | |||
San Juan [Member] | Surface Mine Possible Additional Royalty Assessment Coal Supplier [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimate of Possible Loss Contingency | 5,000,000 | 5,000,000 | |||
San Juan [Member] | Tucson Electric Power Company's Share of Surface Mine Possible Additional Royalty Assessment [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimate of Possible Loss Contingency | 1,000,000 | 1,000,000 | |||
Springerville Unit 1 | |||||
Commitments And Contingencies [Line Items] | |||||
Other Receivables, Gross, Current | 6,000,000 | ||||
Receivable for Capital | 500,000 | ||||
Springerville Unit 1 | Subsequent Event [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Amount paid by Spr Unit 1 Third Party Owners | 0 | ||||
Four Corner [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Percentage of ownership in generating station | 7.00% | 7.00% | |||
Accrual for Environmental Loss Contingency | 1,000,000 | 1,000,000 | |||
Four Corner [Member] | Assessment for Coal Severance Tax, Coal Supplier [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimate of Possible Loss Contingency | 30,000,000 | 30,000,000 | |||
Four Corner [Member] | Tucson Electric Power Company's Share of Assessment for Coal Severance Tax [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimate of Possible Loss Contingency | 1,000,000 | 1,000,000 | |||
Navajo [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Percentage of ownership in generating station | 7.50% | 7.50% | |||
Loss Contingency Accrual, Provision | 1,000,000 | ||||
Estimate of Possible Loss Contingency | $3,000,000 | $2,000,000 |
COMMITMENTS_CONTINGENCIES_AND_4
COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS ENVIRONMENTAL MATTERS (Detail) (USD $) | 12 Months Ended | 3 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2015 | Jan. 31, 2015 |
Commitments And Contingencies [Line Items] | |||||
Jointly Owned Utility Plant, Net Ownership Amount | $706 | ||||
Environmental Costs Recognized, Capitalized in Period | 11 | 5 | 2 | ||
Environmental Remediation Expense | 5 | 8 | 15 | ||
One Year In Future [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimated Environmental Costs To Be Capitalized In Future | 28 | ||||
Estimated Future Annual Operating Costs For Environmental Remediation | 4 | ||||
Two Years In Future Member [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimated Environmental Costs To Be Capitalized In Future | 19 | ||||
Estimated Future Annual Operating Costs For Environmental Remediation | 4 | ||||
Sundt [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimated Capital Expenditure for Monitoring Equipment | 1 | 1 | |||
Estimated Capital Expenditure for Selective Non Catalytic Reduction | 12 | 12 | |||
Jointly Owned Utility Plant, Net Ownership Amount | 17 | 17 | |||
Sundt [Member] | Minimum [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction | 5 | 5 | |||
Sundt [Member] | Maximum [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction | 6 | 6 | |||
Four Corner [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 7.00% | 7.00% | |||
Estimated Capital Expenditure for Selective Catalytic Reduction | 44 | ||||
Estimated Capital Expenditure for Selective Catalytic Reduction | 2 | 2 | |||
Estimated Capital Expenditure for Selective Catalytic Reduction | 35 | ||||
Springerville Unit 1 | |||||
Commitments And Contingencies [Line Items] | |||||
Estimated Future Capital Cost For Mercury Emission Control Equipment | 5 | ||||
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment | 1 | ||||
Third-Party Participating in Ownership Interest | 50.50% | ||||
TEP's Share (in Percentage) of Obligations for Environmental Costs | 100.00% | ||||
Springerville Unit 1 | Completion of Purchase of Equity Interest [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 49.50% | ||||
Navajo [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimated Future Capital Cost For Mercury Emission Control Equipment | 1 | 1 | |||
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment | 1 | 1 | |||
Jointly Owned Utility Plant, Proportionate Ownership Share | 7.50% | 7.50% | |||
Estimated Capital Expenditure for Selective Catalytic Reduction | 28 | ||||
Estimated Capital Expenditure for Selective Catalytic Reduction | 1 | 1 | |||
Better Than BART Agreement Year by which to Shut Down One Unit | 2020 | 2020 | |||
Better than BART Agreement, Year by which SCR Technology to be Installed | 2030 | 2030 | |||
Estimated Capital Expenditure for Selective Catalytic Reduction | 28 | 28 | |||
Estimated Future Annual Operating Costs For Mercury Emission Control Equipment and Baghouses, Less Than | 1 | 1 | |||
Estimate of Possible Loss Contingency | 2 | 3 | |||
San Juan [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 50.00% | 50.00% | |||
Estimated Capital Expenditure for Selective Catalytic Reduction | 37 | ||||
Estimated Capital Expenditure for Selective Catalytic Reduction | 1 | 1 | |||
Estimated Capital Expenditure for Selective Catalytic Reduction | 37 | ||||
San Juan Unit One [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimated Capital Expenditure for Selective Non Catalytic Reduction | 12 | ||||
Estimated Future Change in Operating Cost for Selective Non Catalytic Reduction | 1 | ||||
BalancedDraftUpgradePortionOfEstimatedCapitalExpenditureForSelectiveCatalyticReduction | 25 | ||||
San Juan Unit Two [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Jointly Owned Utility Plant, Net Ownership Amount | 110 | 109 | |||
Springerville [Member] | |||||
Commitments And Contingencies [Line Items] | |||||
Estimated Future Capital Cost For Mercury Emission Control Equipment | 5 | ||||
Estimated Future Annual Operating Costs for Mercury Emission Control Equipment | $1 | ||||
Third-Party Participating in Ownership Interest | 50.50% | ||||
TEP's Share (in Percentage) of Obligations for Environmental Costs | 100.00% |
EMPLOYEE_BENEFIT_PLANS_Compone
EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Pension Plan, Defined Benefit [Member] | |||||
Components of Net Periodic Benefit Plan Cost [Line Items] | |||||
Service Cost | $3 | $2 | $10 | $11 | $9 |
Interest Cost | 4 | 4 | 16 | 14 | 15 |
Expected Return on Plan Assets | -6 | -5 | -21 | -19 | -17 |
Actuarial Loss Amortization | 2 | 1 | 3 | 8 | 7 |
Net Periodic Benefit Cost | 3 | 2 | 8 | 14 | 14 |
Other Retiree Benefits [Member] | |||||
Components of Net Periodic Benefit Plan Cost [Line Items] | |||||
Service Cost | 1 | 1 | 4 | 3 | 3 |
Interest Cost | 1 | 0 | 3 | 3 | 3 |
Expected Return on Plan Assets | 0 | 0 | -1 | -1 | 0 |
Actuarial Loss Amortization | 0 | 0 | 0 | 0 | 0 |
Net Periodic Benefit Cost | $2 | $1 | $6 | $5 | $6 |
FAIR_VALUE_MEASUREMENTS_AND_DE2
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Detail) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | |||
Assets | |||
Cash Equivalent | $50 | $15 | |
Restricted Cash | 2 | 2 | 2 |
Rabbi Trust Investments | 27 | 26 | 22 |
Total Assets | 80 | 45 | 26 |
Liabilities | |||
Liabilities | -30 | -25 | 10 |
Net Total Assets (Liabilities) | 50 | 20 | 16 |
Energy Contracts [Member] | |||
Assets | |||
Derivative Assets | 2 | ||
Liabilities | |||
Derivative Liability | -2 | ||
Energy Contracts Cash Flow Hedge [Member] | |||
Liabilities | |||
Derivative Liability | -1 | ||
Interest Rate Swap [Member] | |||
Liabilities | |||
Derivative Liability | -7 | ||
Energy Related Derivative [Member] | |||
Assets | |||
Derivative Assets | 1 | 2 | |
Liabilities | |||
Derivative Liability | -25 | -18 | |
Energy Contracts Cash Flow Hedge [Member] | |||
Liabilities | |||
Derivative Liability | -1 | -1 | |
Interest Rate Swap [Member] | |||
Liabilities | |||
Derivative Liability | -4 | -5 | |
Energy Contracts [Member] | |||
Assets | |||
Derivative Assets | 1 | ||
Energy Contracts - No Regulatory Recovery [Member] | |||
Assets | |||
Derivative Assets | 1 | ||
Liabilities | |||
Derivative Liability | -1 | ||
Level 1 [Member] | |||
Assets | |||
Cash Equivalent | 50 | 15 | |
Restricted Cash | 2 | 2 | 2 |
Total Assets | 52 | 17 | 2 |
Liabilities | |||
Net Total Assets (Liabilities) | 52 | 17 | 2 |
Level 2 [Member] | |||
Assets | |||
Rabbi Trust Investments | 27 | 26 | 22 |
Total Assets | 27 | 26 | 23 |
Liabilities | |||
Liabilities | -17 | -14 | -7 |
Net Total Assets (Liabilities) | 10 | 12 | 16 |
Level 2 [Member] | Energy Contracts [Member] | |||
Assets | |||
Derivative Assets | 1 | ||
Level 2 [Member] | Interest Rate Swap [Member] | |||
Liabilities | |||
Derivative Liability | -7 | ||
Level 2 [Member] | Energy Related Derivative [Member] | |||
Liabilities | |||
Derivative Liability | -13 | -9 | |
Level 2 [Member] | Interest Rate Swap [Member] | |||
Liabilities | |||
Derivative Liability | -4 | -5 | |
Level 3 [Member] | |||
Assets | |||
Derivative Assets | 1 | 2 | 1 |
Total Assets | 1 | 2 | 1 |
Liabilities | |||
Derivative Liability | -13 | -11 | -3 |
Liabilities | -13 | -11 | -3 |
Net Total Assets (Liabilities) | -12 | -9 | -2 |
Level 3 [Member] | Energy Contracts [Member] | |||
Assets | |||
Derivative Assets | 1 | ||
Liabilities | |||
Derivative Liability | -2 | ||
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member] | |||
Liabilities | |||
Derivative Liability | -1 | ||
Level 3 [Member] | Energy Related Derivative [Member] | |||
Assets | |||
Derivative Assets | 1 | 2 | |
Liabilities | |||
Derivative Liability | -12 | -9 | |
Level 3 [Member] | Energy Contracts Cash Flow Hedge [Member] | |||
Liabilities | |||
Derivative Liability | -1 | -1 | |
Level 3 [Member] | Energy Contracts [Member] | |||
Assets | |||
Derivative Assets | 1 | ||
Level 3 [Member] | Energy Contracts - No Regulatory Recovery [Member] | |||
Assets | |||
Derivative Assets | 1 | ||
Liabilities | |||
Derivative Liability | -1 | ||
Netting [Member] | |||
Assets | |||
Total Assets | -1 | -2 | -1 |
Liabilities | |||
Liabilities | 1 | 2 | 1 |
Netting [Member] | Energy Contracts [Member] | |||
Assets | |||
Derivative Assets | -1 | ||
Liabilities | |||
Derivative Liability | 1 | ||
Netting [Member] | Energy Related Derivative [Member] | |||
Assets | |||
Derivative Assets | -1 | -2 | |
Liabilities | |||
Derivative Liability | 1 | 1 | |
Netting [Member] | Energy Contracts [Member] | |||
Assets | |||
Derivative Assets | -1 | ||
Netting [Member] | Energy Contracts - No Regulatory Recovery [Member] | |||
Assets | |||
Derivative Assets | -1 | ||
Liabilities | |||
Derivative Liability | 1 | ||
Net Fair Value [Member] | |||
Assets | |||
Cash Equivalent | 50 | 15 | |
Restricted Cash | 2 | 2 | 2 |
Rabbi Trust Investments | 27 | 26 | 22 |
Total Assets | 79 | 43 | 25 |
Liabilities | |||
Liabilities | -29 | -23 | -9 |
Net Total Assets (Liabilities) | 50 | 20 | 16 |
Net Fair Value [Member] | Energy Contracts [Member] | |||
Assets | |||
Derivative Assets | 1 | ||
Liabilities | |||
Derivative Liability | -1 | ||
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member] | |||
Liabilities | |||
Derivative Liability | -1 | ||
Net Fair Value [Member] | Interest Rate Swap [Member] | |||
Liabilities | |||
Derivative Liability | -7 | ||
Net Fair Value [Member] | Energy Related Derivative [Member] | |||
Liabilities | |||
Derivative Liability | -24 | -17 | |
Net Fair Value [Member] | Energy Contracts Cash Flow Hedge [Member] | |||
Liabilities | |||
Derivative Liability | -1 | -1 | |
Net Fair Value [Member] | Interest Rate Swap [Member] | |||
Liabilities | |||
Derivative Liability | ($4) | ($5) |
FAIR_VALUE_MEASUREMENTS_AND_DE3
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Detail) (USD $) | 3 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2015 | Sep. 30, 2015 |
Derivative [Line Items] | ||||
Amount Recorded to Capital Lease Interest Expense, Less Than | $0.50 | $1 | ||
Amount Recorded to Long-Term Debt Interest Expense, Less Than | 0.5 | |||
Scenario, Forecast [Member] | ||||
Derivative [Line Items] | ||||
Estimated loss expected to be reclassified to earnings within the next twelve months | $3 | $3 |
FAIR_VALUE_MEASUREMENTS_AND_DE4
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Detail) (USD $) | 12 Months Ended | 36 Months Ended | 3 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2017 | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Derivative, Term of Contract | 3 years | |||||
Unrealized Gain (Loss) on Energy Contracts | $1 | |||||
Regulatory Recovery [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Unrealized Net Gain (Loss) Recorded in Regulatory (Assets) Liabilities | ($18) | ($6) | $1 | $0 | $6 |
FAIR_VALUE_MEASUREMENTS_AND_DE5
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Detail) | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
GWh | GWh | GWh | |
Power Contracts (in GWh) [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivatives Volumes | 1,008 | 2,604 | 779 |
Gas Contracts (in GBtu) [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Derivatives Volumes | 24,027,000,000 | 19,932,000,000 | 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 $) | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | |||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |||
Derivative Assets | $1 | $2 | $1 |
Derivative Liability | -13 | -11 | -3 |
Market Approach Valuation Technique [Member] | Forward Contracts [Member] | |||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |||
Derivative Assets | 1 | 1 | |
Derivative Liability | -8 | -6 | -3 |
Market Approach Valuation Technique [Member] | Call Option [Member] | |||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |||
Derivative Assets | 1 | ||
Derivative Liability | -1 | ||
Valuation Technique Option Model [Member] | Options Held [Member] | |||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |||
Derivative Assets | 1 | ||
Derivative Liability | ($5) | ($4) | |
Minimum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member] | |||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |||
Market price per MWh | 23.8 | 22.35 | 27 |
Minimum [Member] | Market Approach Valuation Technique [Member] | Call Option [Member] | |||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |||
Market price per MWh | 27.75 | ||
Market price per MMbtu | 2.88 | ||
Minimum [Member] | Valuation Technique Option Model [Member] | Options Held [Member] | |||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |||
Market price per MMbtu | 2.34 | 2.72 | 3.88 |
Gas volatility | 24.15% | 30.80% | 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 | 37.7 | 39.05 | 48.25 |
Maximum [Member] | Market Approach Valuation Technique [Member] | Call Option [Member] | |||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |||
Market price per MWh | 44.94 | ||
Market price per MMbtu | 4.02 | ||
Maximum [Member] | Valuation Technique Option Model [Member] | Options Held [Member] | |||
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items] | |||
Market price per MMbtu | 3.22 | 3.26 | 4.32 |
Gas volatility | 39.91% | 53.29% | 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 | 12 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 |
Fair Value Measurementsand Derivative Instruments Disclosure [Abstract] | ||||
Beginning balance | ($9) | ($2) | ($2) | $0 |
Realized/Unrealized Gains/(Losses) Recorded to: | ||||
Net Regulatory Assets/Liabilities - Derivative Instruments | -2 | -1 | -8 | -2 |
Settlements | -1 | 1 | 1 | 0 |
Ending balance | -12 | -2 | -9 | -2 |
Gains Losses Attributable To Change In Unrealized Gains Or Losses Relating To Assets Liabilities Still Held At End Of Period | ($3) | $0 | ($8) | ($1) |
FAIR_VALUE_MEASUREMENTS_AND_DE8
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Detail) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Derivative [Line Items] | |||
FV of derivative instruments in net liability position with credit risk related features | $27,000,000 | $21,000,000 | $5,000,000 |
Collateral Held from Counterparties | 0 | 0 | |
Additional collateral if credit-risk contingent features are triggered | 27,000,000 | 21,000,000 | |
Collateral Already Posted, Aggregate Fair Value | 0 | ||
Letters of Credit Outstanding, Amount | 1,000,000 | ||
Cash Collateral [Member] | |||
Derivative [Line Items] | |||
Collateral Already Posted, Aggregate Fair Value | 0 | ||
Line of Credit Collateral [Member] | |||
Derivative [Line Items] | |||
Collateral Already Posted, Aggregate Fair Value | $500,000 |
FAIR_VALUE_MEASUREMENTS_AND_DE9
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Detail) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-Term Debt | $1,541,486,000 | $1,372,414,000 | $1,223,070,000 |
Level 2 [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt, Fair Value | 1,642,000,000 | 1,457,000,000 | 1,214,000,000 |
Level 3 [Member] | Carrying Value [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Investment in Lease Equity(1) | 36,000,000 | ||
Level 3 [Member] | Fair Value [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Investment in Lease Equity(1) | $25,000,000 |
RECENTLY_ISSUED_ACCOUNTING_PRO1
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS (Detail) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Accounting Policies [Abstract] | ||
Unamortized Debt Issuance Expense | $12 | $11 |
Deferred Finance Costs, Current, Net | $1 | $1 |
NATURE_OF_OPERATIONS_AND_SUMMA
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES FORTIS ACQUISITION OF UNS ENERGY (Detail) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Aug. 15, 2014 | |
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 | $220,000,000 | |||
Contribution To Parent of Filer | 287,000,000 | |||
Equity Investment from UNS Energy | 225,000,000 | 0 | 0 | |
Merger-Related Costs Recorded through Closing of Merger | 15,000,000 | |||
Share Based Comp Accelerated Vesting Expense | 2,000,000 | |||
Total share-based compensation expense | 5,000,000 | 3,000,000 | 2,000,000 | |
Total Bill Credit Refunds Over 5 Years [Member] | ||||
Fortis Acquisition Direct Customer Bill Credits | 19,000,000 | |||
Years Over Which Fortis Acquisition Bill Credit Are Paid | 5 years | |||
Bill Credit Refunds in Year 1 [Member] | ||||
Fortis Acquisition Direct Customer Bill Credits | 6,000,000 | |||
Annual Bill Credit Refunds in Years 2 Through 5 [Member] | ||||
Fortis Acquisition Direct Customer Bill Credits | 3,000,000 | |||
Fortis Inc. [Member] | ||||
Business Acquisition, Share Price | $60.25 | |||
UNS Energy to TEP [Member] | ||||
Equity Investment from UNS Energy | $225,000,000 |
NATURE_OF_OPERATIONS_AND_SUMMA1
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Prior Period Adjustment) (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 |
NATURE_OF_OPERATIONS_AND_SUMMA2
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (AFUDC Rates) (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Disclosure Nature Of Operations And Summary Of Significant Accounting Policies Afudc Rates [Abstract] | |||
Average AFUDC Rate on Regulated Construction Expenditures | 7.30% | 7.38% | 7.22% |
NATURE_OF_OPERATIONS_AND_SUMMA3
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Summary of Average Annual Depreciation Rates for All Utility Plants) (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Disclosure Nature Of Operations And Summary Of Significant Accounting Policies Summary Of Average Annual Depreciation Rates For All Utility Plants [Abstract] | |||
Average annual depreciation rate | 2.99% | 3.16% | 3.22% |
NATURE_OF_OPERATIONS_AND_SUMMA4
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (INVESTMENTS IN LEASE EQUITY) (Detail) | 0 Months Ended | ||
Nov. 30, 2014 | Dec. 29, 2014 | Dec. 31, 2014 | |
Springerville Unit 1 | |||
Equity Method Investment, Ownership Percentage | 14.10% | ||
Equity Method Investment, Ownership Period | Prior to December 2014 | ||
Springerville Common Facilities | |||
Equity Method Investment, Ownership Percentage | 7.00% |
NATURE_OF_OPERATIONS_AND_SUMMA5
NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (RENEWABLE ENERGY EFFICIENCY PROGRAMS) (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Renewable Energyand Energy Efficiency Standards [Abstract] | |
Renewable Energy Target Percentage | 15.00% |
Distributed Generation Requirement Target Percentage | 30.00% |
Renewable Energy Standard, Year by which target is reached | 2025 |
Percentage of Electric Energy Efficiency Standards Target Retail Savings on Sales | 22.00% |
Energy Efficiency Standard, Year by which target retail saving is reached | 2020 |
REGULATORY_MATTERS_Rate_Order_
REGULATORY MATTERS (Rate Order) (Detail) (USD $) | 1 Months Ended |
Jun. 30, 2013 | |
Schedule of Regulatory Orders [Line Items] | |
Base rate increase approved | $76,000,000 |
Expected change in annual depreciation | 11,000,000 |
Environmental compliance adjustor capped rate | $0.00 |
Retail revenue cap on environmental compliance adjustor | 0.25% |
Before July 1, 2013 [Member] | |
Schedule of Regulatory Orders [Line Items] | |
Change in composite rate | 3.32% |
After June 30, 2013 [Member] | |
Schedule of Regulatory Orders [Line Items] | |
Change in composite rate | 3.00% |
REGULATORY_MATTERS_Detail
REGULATORY MATTERS (Detail) (USD $) | 0 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | 6 Months Ended | 10 Months Ended | |||
1-May-14 | Aug. 31, 2014 | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Apr. 30, 2014 | Jun. 30, 2013 | Apr. 30, 2014 | |
Schedule of Regulatory Cost Recovery Mechanisms [Line Items] | ||||||||||
Purchased Power And Fuel Adjustment Clause Rate | 0.005 | 0.0014 | ||||||||
Mine Fire Cost Deferral | $10,000,000 | $2,000,000 | $10,000,000 | |||||||
Mine Fire Insurance Settlement Proceeds | 8,000,000 | |||||||||
Environmental Compliance Adjustor Rate | 0.000049 | 0.000049 | ||||||||
Environmental Compliance Adjustor Effective Date | 1-May-14 | |||||||||
Regulated Operating Revenue, Other | 1,000,000 | |||||||||
Energy Efficiency Budget Spending | 40,000,000 | |||||||||
Approved Energy Efficiency Budget | 33,000,000 | |||||||||
Amount receivable as return on investment | 1,000,000 | 2,000,000 | ||||||||
Energy Efficiency Performance Incentive | 3,000,000 | 2,000,000 | ||||||||
Cap on increase in lost fixed cost recovery rate | 1.00% | 1.00% | ||||||||
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% | |||||||||
Revenue Recognized Under Lost Fixed Cost Recovery Mechanism | $3,000,000 | $5,000,000 | $11,327,000 | $2,171,000 | $0 | |||||
May Through September 2014 [Member] | ||||||||||
Schedule of Regulatory Cost Recovery Mechanisms [Line Items] | ||||||||||
Purchased Power And Fuel Adjustment Clause Rate | 0.001 | |||||||||
October 2014 Through March 2015 [Member] | ||||||||||
Schedule of Regulatory Cost Recovery Mechanisms [Line Items] | ||||||||||
Purchased Power And Fuel Adjustment Clause Rate | 0.005 | |||||||||
January 2013 through June 2013 [Member] | ||||||||||
Schedule of Regulatory Cost Recovery Mechanisms [Line Items] | ||||||||||
Purchased Power And Fuel Adjustment Clause Rate | 0.0077 | |||||||||
July 2013 through April 2014 [Member] | ||||||||||
Schedule of Regulatory Cost Recovery Mechanisms [Line Items] | ||||||||||
Purchased Power And Fuel Adjustment Clause Rate | 0.0014 |
Recovered_Sheet1
REGULATORY MATTERS (Regulatory Assets and Liabilities) (Detail) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Disclosure Regulatory Matters Regulatory Assets And Liabilities [Abstract] | |||
Property Tax Deferrals Current | $21,000,000 | $20,000,000 | |
PPFAC | 19,000,000 | 4,000,000 | |
Derivative Instruments Regulatory Assets Current | 15,000,000 | 1,000,000 | |
DSM and LFCR Regulatory Assets Current | 8,000,000 | 3,000,000 | |
Mine Fire Cost Deferral | 10,000,000 | 2,000,000 | 10,000,000 |
Other Current Regulatory Assets | 4,000,000 | 5,000,000 | |
Regulatory Assets-Current | 79,380,000 | 69,383,000 | 42,555,000 |
Pension And Other Postretirement Benefits Noncurrent | 126,000,000 | 75,000,000 | |
Income Taxes Recoverable through Future Revenues | 31,000,000 | 22,000,000 | |
PPFAC-Final Mine Reclamation and Retiree Health Care Costs | 29,000,000 | 25,000,000 | |
Lease Purchase Commitment Deferral | 16,000,000 | 2,000,000 | |
Loss on Reacquired Debt Regulatory Asset | 6,000,000 | 7,000,000 | |
LFCR Regulatory Asset Non-Current | 4,000,000 | ||
Tucson to Nogales Transmission Line | 4,000,000 | 5,000,000 | |
Other Regulatory Assets Noncurrent | 7,000,000 | 5,000,000 | |
Regulatory Assets-Noncurrent | 238,018,000 | 223,192,000 | 141,030,000 |
RES | -28,000,000 | -22,000,000 | |
DSM Current Regulatory Liability | -6,000,000 | ||
Customer Credit Current Regulatory Liability | -5,000,000 | ||
Other Current Regulatory Liabilities Current | -2,000,000 | ||
Regulatory Liabilities - Current | -33,308,000 | -38,847,000 | -23,701,000 |
Net Cost of Removal for Interim Retirements | -265,000,000 | -254,000,000 | |
Deferred Investment Tax Credit | -25,000,000 | -4,000,000 | |
Income Taxes Payable through Future Rates | -20,000,000 | -5,000,000 | |
Customer Credit Noncurrent Regulatory Liability | -11,000,000 | 0 | |
Regulatory Liability, Noncurrent | -313,062,000 | -321,186,000 | -263,270,000 |
Total Net Regulatory Assets (Liabilities) | ($68,000,000) | ($103,000,000) |
REGULATORY_MATTERS_Regulatory_1
REGULATORY MATTERS (Regulatory Assets and Liabilities Footnotes) (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Regulatory Assets [Line Items] | |
Property Tax Recovery Period | 6 months |
Recovery Period for Rate Case Costs | 3 years |
Recovery Period of Environmental Compliance Adjustor | 1 year |
Total Bill Credit Refunds Over 5 Years [Member] | |
Regulatory Assets [Line Items] | |
Years Over Which Fortis Acquisition Bill Credit Are Paid | 5 years |
Minimum [Member] | |
Regulatory Assets [Line Items] | |
Expected Life Of Mines | 14 years |
Maximum [Member] | |
Regulatory Assets [Line Items] | |
Expected Life Of Mines | 20 years |
UTILITY_PLANT_AND_JOINTLYOWNED2
UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Company and Major Class) (Detail) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Plant in Service: | |||
Total Plant in Service | $5,225,923,000 | $5,175,148,000 | $4,467,667,000 |
Utility Plant under Capital Leases | 667,000,000 | 638,000,000 | |
Electricity Generation Plant, Non-Nuclear [Member] | |||
Plant in Service: | |||
Total Plant in Service | 2,388,000,000 | 1,889,000,000 | |
Electric Transmission Plant [Member] | |||
Plant in Service: | |||
Total Plant in Service | 898,000,000 | 825,000,000 | |
Electric Distribution Plant [Member] | |||
Plant in Service: | |||
Total Plant in Service | 1,398,000,000 | 1,298,000,000 | |
General Plant [Member] | |||
Plant in Service: | |||
Total Plant in Service | 338,000,000 | 312,000,000 | |
Software Costs [Member] | |||
Plant in Service: | |||
Total Plant in Service | 149,000,000 | 141,000,000 | |
Electric Plant Held for Future Use [Member] | |||
Plant in Service: | |||
Total Plant in Service | $4,000,000 | $3,000,000 |
UTILITY_PLANT_AND_JOINTLYOWNED3
UTILITY PLANT AND JOINTLY-OWNED FACILITES (Utility Plant in Service by Company and Major Class Footnotes) (Parenthetical) (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Disclosure Utility Plant And Jointly Owned Facilities Utility Plant In Service By Company And Major Class [Abstract] | |||
Capitalized Computer Software, Gross | $31 | $39 | |
Amortization of computer software costs | $17 | $14 | $13 |
UTILITY_PLANT_AND_JOINTLYOWNED4
UTILITY PLANT AND JOINTLY-OWNED FACILITES (Amount of Lease Expense Incurred for TEP's Generation-Related Capital Leases) (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||||
Capital Leases | $1,004,000 | $3,921,000 | $10,249,000 | $25,140,000 | $33,613,000 |
Interest Expense - Included in: | |||||
Total Lease Expense | 33,000,000 | 47,000,000 | 55,000,000 | ||
Operating Expenses - Fuel | |||||
Interest Expense - Included in: | |||||
Interest Expense | 1,000,000 | 2,000,000 | 3,000,000 | ||
Amortization of Capital Lease Assets | 6,000,000 | 5,000,000 | 4,000,000 | ||
Operating Expenses - Amortization [Member] | |||||
Interest Expense - Included in: | |||||
Amortization of Capital Lease Assets | $16,000,000 | $15,000,000 | $14,000,000 |
UTILITY_PLANT_AND_JOINTLYOWNED5
UTILITY PLANT AND JOINTLY-OWNED FACILITES (Depreciable Lives of Utility Plant in Service) (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation Rate | 2.99% | 3.16% | 3.22% |
Generation Plant | 22 years | ||
Transmission Plant | 32 years | ||
Distribution Plant | 35 years | ||
General Plant | 11 years | ||
Electric Generation Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation Rate | 3.31% | ||
Electric Transmission Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation Rate | 1.48% | ||
Electric Distribution Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation Rate | 2.08% | ||
General Plant [Member] | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Depreciation Rate | 5.48% |
UTILITY_PLANT_AND_JOINTLYOWNED6
UTILITY PLANT AND JOINTLY-OWNED FACILITES (Depreciable Lives of Utility Plant in Service Footnotes) (Parenthetical) (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Minimum [Member] | Application Software [Member] | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Finite-Lived Intangible Asset, Useful Life | 3 years |
Minimum [Member] | Other Intangible Assets [Member] | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Finite-Lived Intangible Asset, Useful Life | 5 years |
Maximum [Member] | Application Software [Member] | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Finite-Lived Intangible Asset, Useful Life | 1 year |
Maximum [Member] | Other Intangible Assets [Member] | |
Public Utility, Property, Plant and Equipment [Line Items] | |
Finite-Lived Intangible Asset, Useful Life | 6 years |
UTILITY_PLANT_AND_JOINTLYOWNED7
UTILITY PLANT AND JOINTLY-OWNED FACILITES (TEP's Interests in Jointly-Owned Generating Stations and Transmission Systems) (Detail) (USD $) | Dec. 31, 2014 | Jan. 31, 2015 |
In Millions, unless otherwise specified | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Plant in Service | $1,364 | |
Construction Work in Progress | 33 | |
Accumulated Depreciation | 691 | |
Net Book Value | 706 | |
San Juan Units 1 and 2 [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Percentage of ownership in generating station | 50.00% | |
Plant in Service | 453 | |
Construction Work in Progress | 8 | |
Accumulated Depreciation | 242 | |
Net Book Value | 219 | |
Navajo Units 1, 2, and 3 [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Percentage of ownership in generating station | 7.50% | |
Plant in Service | 153 | |
Construction Work in Progress | 1 | |
Accumulated Depreciation | 112 | |
Net Book Value | 42 | |
Four Corners Units 4 and 5 [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Percentage of ownership in generating station | 7.00% | |
Plant in Service | 104 | |
Construction Work in Progress | 3 | |
Accumulated Depreciation | 77 | |
Net Book Value | 30 | |
Luna Energy Facility [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Percentage of ownership in generating station | 33.30% | |
Plant in Service | 55 | |
Construction Work in Progress | 0 | |
Accumulated Depreciation | 2 | |
Net Book Value | 53 | |
GIla River Unit 3 [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Percentage of ownership in generating station | 75.00% | |
Plant in Service | 186 | |
Construction Work in Progress | 0 | |
Accumulated Depreciation | 54 | |
Net Book Value | 132 | |
Gila River Common Facilities [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Percentage of ownership in generating station | 18.75% | |
Plant in Service | 42 | |
Construction Work in Progress | 0 | |
Accumulated Depreciation | 11 | |
Net Book Value | 31 | |
Transmission Facilities [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Plant in Service | 371 | |
Construction Work in Progress | 21 | |
Accumulated Depreciation | 193 | |
Net Book Value | $199 | |
Springerville Unit 1 | Priorto Purchaseof Equity Interest [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Percentage of ownership in generating station | 24.70% | |
Springerville Unit 1 | Additional Purchase of Equity Interest [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Percentage of ownership in generating station | 24.80% | |
Springerville Unit 1 | Completion of Purchase of Equity Interest [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Percentage of ownership in generating station | 49.50% |
UTILITY_PLANT_AND_JOINTLYOWNED8
UTILITY PLANT AND JOINTLY-OWNED FACILITES (Schedule of Asset Retirement Obligations) (Detail) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Disclosure Utility Plant And Jointly Owned Facilities Schedule Of Asset Retirement Obligations [Abstract] | ||
Beginning Balance | $22 | $14 |
Asset Retirement Obligation, Liabilities Incurred | 5 | 0 |
Accretion Expense | 1 | 1 |
Revision to Estimated Cash Flows | 0 | 7 |
Ending Balance | $28 | $22 |
DEBT_CREDIT_FACILITIES_AND_CAP
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Detail) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | ||||||||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Oct. 31, 2013 | Mar. 31, 2014 | Apr. 30, 2013 | Sep. 30, 2012 | Mar. 31, 2013 | Dec. 31, 2010 | Aug. 31, 2009 | |
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||||
Repayment of outstanding credit facility | $100,000,000 | $105,000,000 | $190,000,000 | $78,000,000 | $199,000,000 | |||||||
Collateralized Mortgage Backed Securities [Member] | ||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||||
Debt extinguishment | 423,000,000 | |||||||||||
Amount of 1992 mortgage bonds used to secure letter of credit facilities | 423,000,000 | |||||||||||
Revolving Credit Facility [Member] | ||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||||
Repayment of outstanding credit facility | 90,000,000 | |||||||||||
Unsecured Debt [Member] | ||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||||
Debt face amount | 150,000,000 | 150,000,000 | 150,000,000 | 91,000,000 | ||||||||
Fixed interest rate of long-term debt | 5.00% | 5.75% | 5.00% | 6.38% | 3.85% | 4.00% | ||||||
Debt extinguishment | 193,000,000 | 91,000,000 | ||||||||||
Unsecured Debt [Member] | Variable Rate Bonds [Member] | ||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||||
Debt face amount | 100,000,000 | |||||||||||
Effective interest rate | 0.87% | 0.95% | ||||||||||
Unsecured Debt [Member] | Minimum [Member] | ||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||||
Fixed interest rate of long-term debt | 0.85% | |||||||||||
Unsecured Debt [Member] | Maximum [Member] | ||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||||
Fixed interest rate of long-term debt | 0.95% | |||||||||||
Line of Credit [Member] | Revolving Credit Facility [Member] | ||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||||
Repayment of outstanding credit facility | 72,000,000 | |||||||||||
Variable Rate Demand Obligation [Member] | ||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||||
Debt face amount | 115,000,000 | 37,000,000 | ||||||||||
Debt extinguishment | 100,000,000 | |||||||||||
Derivative amount of hedged item | $50,000,000 | |||||||||||
Fixed rate of interest related to interest rate swap | 2.40% |
DEBT_CREDIT_FACILITIES_AND_CAP1
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Interest Rates on TEP's Variable Rate IDBs) (Detail) (Variable Rate Demand Obligation [Member]) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Variable Rate Demand Obligation [Member] | |||
Schedule Of Interest Rate [Line Items] | |||
Average Interest Rate | 0.08% | 0.10% | 0.17% |
Range of Average weekly interest rate, minimum | 0.05% | 0.06% | 0.06% |
Average Weekly Interest Rate Range Maximum | 0.13% | 0.25% | 0.26% |
DEBT_CREDIT_FACILITIES_AND_CAP2
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Credit agreements) (Detail) (USD $) | 1 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | ||||||
Apr. 30, 2013 | Dec. 31, 2012 | Jan. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Sep. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2010 | Feb. 25, 2014 | |
Revolving Credit Facility [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Line of credit facility borrowing capacity | $200,000,000 | |||||||||
Outstanding borrowings under the company credit agreement | 70,000,000 | |||||||||
Remaining borrowing capacity | 185,000,000 | |||||||||
Letter of Credit [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Line of credit facility borrowing capacity | 82,000,000 | |||||||||
Subsequent Event [Member] | Revolving Credit Facility [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Outstanding borrowings under the company credit agreement | 70,000,000 | |||||||||
Remaining borrowing capacity | 170,000,000 | |||||||||
Unsecured Debt [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Debt extinguishment | 91,000,000 | 193,000,000 | ||||||||
Fixed interest rate of long-term debt | 6.38% | 5.75% | 5.00% | 4.00% | 3.85% | |||||
Debt face amount | 150,000,000 | 91,000,000 | 150,000,000 | |||||||
Unsecured Debt [Member] | Subsequent Event [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Debt extinguishment | 130,000,000 | |||||||||
Lineof Credit 2014 [Member] | Revolving Credit Facility 2014 [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Interest rate spread on LIBOR borrowing | 0.75% | |||||||||
Interest rate in addition to alternate base rate for alternate base rate loans | 0.75% | |||||||||
Outstanding borrowings under the company credit agreement | 0 | |||||||||
Line of Credit [Member] | Revolving Credit Facility [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Interest rate spread on LIBOR borrowing | 1.13% | |||||||||
Interest rate in addition to alternate base rate for alternate base rate loans | 0.13% | |||||||||
Outstanding borrowings under the company credit agreement | 15,000,000 | 0 | ||||||||
Line of Credit [Member] | Letter of Credit [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Outstanding borrowings under the company credit agreement | 1,000,000 | 1,000,000 | ||||||||
Variable Rate Demand Obligation [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Debt extinguishment | 100,000,000 | |||||||||
Debt face amount | 115,000,000 | 37,000,000 | ||||||||
Letter of Credit [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Outstanding borrowings under the company credit agreement | 37,000,000 | |||||||||
Letter of Credit [Member] | Subsequent Event [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Commitment fee percentage | 1.00% | |||||||||
Unsecured Term Loans [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Short-term debt | 130,000,000 | |||||||||
Short-term debt, amount outstanding | 130,000,000 | |||||||||
Unsecured Term Loans [Member] | Subsequent Event [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Short-term debt | 130,000,000 | |||||||||
Revolving Credit Facility 2014 [Member] | ||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | ||||||||||
Line of credit facility borrowing capacity | $70,000,000 |
DEBT_CREDIT_FACILITIES_AND_CAP3
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (TEP Capital Lease) (Detail) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | ||||||||||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jan. 31, 2013 | Oct. 31, 2013 | Apr. 30, 2014 | Jan. 31, 2014 | Apr. 30, 2015 | Jan. 31, 2015 | Jun. 30, 2015 | Apr. 30, 2016 | |
MW | MW | ||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Repayments of long-term capital lease obligations | $8,394,000 | $79,737,000 | $165,145,000 | $99,621,000 | $89,452,000 | ||||||||
Generating Capacity Purchased, in MWs | 192 | ||||||||||||
Springerville Unit One Lease Debt [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Proceeds from collection of lease receivables | 9,000,000 | ||||||||||||
Equity method investment, aggregate cost | 36,000,000 | ||||||||||||
Lease Equity Investment to Plant in Service | 36,000,000 | ||||||||||||
Springerville Common Facilities Lease Debt [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Derivative basis spread | 1.75% | 1.75% | |||||||||||
Third Party Owner [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Third party owners share of capital expenditures | 7,000,000 | ||||||||||||
Third party owners share of O&M expenses | 1,500,000 | ||||||||||||
Additional Purchase of Equity Interest [Member] | Springerville Unit 1 | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Generating Capacity Purchased, in MWs | 96 | ||||||||||||
Lease arrangement, fair market value purchase price | 46,000,000 | ||||||||||||
Percentage of ownership in generating station | 24.80% | ||||||||||||
Completion of Purchase of Equity Interest [Member] | Springerville Unit 1 | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Generating Capacity Purchased, in MWs | 192 | ||||||||||||
Percentage of ownership in generating station | 49.50% | ||||||||||||
Springerville Unit One Lease [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Percentage of interest committed to purchase | 0.106 | ||||||||||||
Generating Capacity Purchased, in MWs | 41 | 96 | |||||||||||
Lease arrangement, fair market value purchase price | 20,000,000 | 46,000,000 | |||||||||||
Increase in Utility Plant under Capital Lease | 55,000,000 | ||||||||||||
Increase in Capital Lease Obligation | 55,000,000 | ||||||||||||
Springerville Coal Handling Facilities Lease [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Fixed price to acquire leased interest in facilities | 120,000,000 | ||||||||||||
Increase in Utility Plant under Capital Lease | 109,000,000 | ||||||||||||
Increase in Capital Lease Obligation | 109,000,000 | ||||||||||||
Springerville Coal Handling Facilities Lease [Member] | SRP [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Sales Price of Leased Interest In Facilities | 24,000,000 | ||||||||||||
Springerville Coal Handling Facilities Lease [Member] | Tri-State [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Sales Price of Leased Interest In Facilities | 24,000,000 | ||||||||||||
Springerville Common Facilities | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Number of operating lease | 2 | ||||||||||||
Term of contract, renewal | 2 years | ||||||||||||
Springerville Common Facility Lease Part One [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Fixed price to acquire leased interest in facilities | 38,000,000 | ||||||||||||
Springerville Common Facility Lease Part Two [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Fixed price to acquire leased interest in facilities | 68,000,000 | ||||||||||||
Subsequent Event [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Repayments of long-term capital lease obligations | 43,000,000 | 9,000,000 | |||||||||||
Subsequent Event [Member] | Springerville Coal Handling Facilities Lease [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Percentage of ownership in generating station | 100.00% | ||||||||||||
Fixed price to acquire leased interest in facilities | 120,000,000 | ||||||||||||
Subsequent Event [Member] | Springerville Coal Handling Facilities Lease [Member] | SRP [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Sales Price of Leased Interest In Facilities | 24,000,000 | ||||||||||||
Subsequent Event [Member] | Springerville Coal Handling Facilities Lease [Member] | Tri-State [Member] | |||||||||||||
Capital Lease Asset Purchase Commitment [Line Items] | |||||||||||||
Sales Price of Leased Interest In Facilities | $24,000,000 |
DEBT_CREDIT_FACILITIES_AND_CAP4
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Effect of Fixing Interest Rates on Amortizing Principal Balances of Swaps) (Detail) (Springerville Common Facilities Lease Debt [Member], USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Derivative Instruments And Hedging Activities [Line Items] | ||
Derivative basis spread | 1.75% | 1.75% |
Interest Rate Swap One [Member] | ||
Derivative Instruments And Hedging Activities [Line Items] | ||
Fixed rate of interest related to interest rate swap | 5.77% | |
Derivative basis spread | 1.75% | |
Derivative, notional amount | 32 |
DEBT_CREDIT_FACILITIES_AND_CAP5
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt) (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Schedule Of Maturities Of Long Term Debt [Line Items] | ||
2015 | $188,000,000 | |
2016 | 95,000,000 | |
2017 | 18,000,000 | |
2018 | 111,000,000 | |
2019 | 49,000,000 | |
Total 2015 - 2019 | 461,000,000 | |
Thereafter | 1,177,000,000 | |
Less: Imputed Interest | -20,000,000 | |
Total | 1,372,414,000 | 1,223,070,000 |
Long-term Debt and Capital Lease Obligations | 1,618,000,000 | |
Long-term Debt [Member] | ||
Schedule Of Maturities Of Long Term Debt [Line Items] | ||
2015 | 0 | |
2016 | 79,000,000 | |
2017 | 0 | |
2018 | 100,000,000 | |
2019 | 37,000,000 | |
Total 2015 - 2019 | 216,000,000 | |
Thereafter | 1,159,000,000 | |
Less: Imputed Interest | 0 | |
Total | 1,375,000,000 | |
Capital Lease Obligations [Member] | ||
Schedule Of Maturities Of Long Term Debt [Line Items] | ||
2015 | 188,000,000 | |
2016 | 16,000,000 | |
2017 | 18,000,000 | |
2018 | 11,000,000 | |
2019 | 12,000,000 | |
Total 2015 - 2019 | 245,000,000 | |
Thereafter | 18,000,000 | |
Less: Imputed Interest | -20,000,000 | |
Total | $243,000,000 |
DEBT_CREDIT_FACILITIES_AND_CAP6
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Maturities of Long-term Debt Footnotes) (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2010 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2013 | Sep. 30, 2012 |
In Millions, unless otherwise specified | ||||||
Variable Rate Demand Obligation [Member] | ||||||
Schedule Of Maturities Of Long Term Debt [Line Items] | ||||||
Debt face amount | $115 | $37 | ||||
Springerville Unit 2 Local Furnishings [Member] | ||||||
Schedule Of Maturities Of Long Term Debt [Line Items] | ||||||
Debt face amount | 100 | |||||
Unsecured Debt [Member] | ||||||
Schedule Of Maturities Of Long Term Debt [Line Items] | ||||||
Debt face amount | 150 | 91 | 150 | |||
Debt discount | $2 |
PURCHASE_OF_GASFIRED_GENERATIO2
PURCHASE OF GAS-FIRED GENERATION FACILITY (Additional Information) (Detail) (USD $) | 3 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2014 |
Unusual or Infrequent Item [Line Items] | |
Utility Plant - Net | $163 |
Materials and Supplies | 2 |
ARO Obligation Assumed | -1 |
Total Purchase Price | 164 |
Entegra, Gila River Generating Station Unit 3 [Member] | |
Unusual or Infrequent Item [Line Items] | |
Letter Of Credit Cancelled | $15 |
Tucson Electric Power Company To Uns Electric [Member] | Entegra, Gila River Generating Station Unit 3 [Member] | |
Unusual or Infrequent Item [Line Items] | |
Generating capacity of plant in MW | 550 |
Tucson Electric Power Company [Member] | Entegra, Gila River Generating Station Unit 3 [Member] | |
Unusual or Infrequent Item [Line Items] | |
Generating capacity of plant in MW | 413 |
Percentage of ownership in Generating Unit | 75.00% |
Uns Electric Incorporated [Member] | Entegra, Gila River Generating Station Unit 3 [Member] | |
Unusual or Infrequent Item [Line Items] | |
Percentage of ownership in Generating Unit | 25.00% |
Springerville Unit 1 | |
Unusual or Infrequent Item [Line Items] | |
Generating capacity of plant in MW | 195 |
San Juan Unit Two [Member] | |
Unusual or Infrequent Item [Line Items] | |
Generating capacity of plant in MW | 170 |
EMPLOYEE_BENEFIT_PLANS_Additio
EMPLOYEE BENEFIT PLANS (Additional Information) (Detail) (USD $) | 12 Months Ended | 252 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2035 | ||
Plans | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Number of defined benefit pension plans | 2 | ||||||
Percentage of net periodic benefit cost that was capitalized | 20.00% | ||||||
Investment Return Model Best-Estimate Range | 20 years | ||||||
Matching 401(k) contributions made | $5 | $5 | $5 | ||||
Level 3 [Member] | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Index value percentage of real estate assets | 100.00% | 85.00% | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 23 | 21 | 19 | ||||
Other Retiree Benefits [Member] | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Employer Contributions | 6 | [1] | 6 | [1] | |||
Effect of plan amendment on obligation | 1 | ||||||
Defined Benefit Plan, Fair Value of Plan Assets | 12 | 10 | 7 | ||||
Other Retiree Benefits [Member] | Regulatory Asset [Member] | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Defined Benefit Plan, Future Amortization of Prior Service Credit (Cost) | 0.5 | ||||||
Pension Plan, Defined Benefit [Member] | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Employer Contributions | 9 | [1] | 22 | [1] | |||
Effect of plan amendment on obligation | 1 | ||||||
Defined Benefit Plan, Accumulated Benefit Obligation | 365 | 297 | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 335 | 307 | 275 | ||||
Effect of plan amendment on future payments | 5 | ||||||
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Defined Benefit Plan, Fair Value of Plan Assets | 23 | 21 | |||||
Pension Plan, Defined Benefit [Member] | Minimum [Member] | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Percentile of investment return model range used | 25.00% | ||||||
Pension Plan, Defined Benefit [Member] | Maximum [Member] | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Percentile of investment return model range used | 75.00% | ||||||
Pension Plan, Defined Benefit [Member] | Regulatory Asset [Member] | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Defined Benefit Plan, Future Amortization of Gain (Loss) | -7 | ||||||
Defined Benefit Plan, Future Amortization of Prior Service Credit (Cost) | 0.5 | ||||||
Pension Plan, Defined Benefit [Member] | Accumulated Other Comprehensive Loss | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Defined Benefit Plan, Future Amortization of Gain (Loss) | -0.5 | ||||||
Defined Benefit Plan, Future Amortization of Prior Service Credit (Cost) | -0.5 | ||||||
Pension Plan, Defined Benefit [Member] | Fixed Income | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Defined Benefit Plan, Fair Value of Plan Assets | 143 | 124 | |||||
Pension Plan, Defined Benefit [Member] | Fixed Income | Level 3 [Member] | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | |||||
VEBA Trust [Member] | Other Retiree Benefits [Member] | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Employer Contributions | 3 | 3 | 3 | ||||
Defined Benefit Plan, Fair Value of Plan Assets | 12 | 10 | |||||
VEBA Trust [Member] | Other Retiree Benefits [Member] | Fixed Income | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Defined Benefit Plan, Fair Value of Plan Assets | 4 | 4 | |||||
VEBA Trust [Member] | Other Retiree Benefits [Member] | VEBA Trust Asset - Equities | |||||||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||||||
Defined Benefit Plan, Fair Value of Plan Assets | $8 | $6 | |||||
[1] | In 2015, TEP expects to contribute $23 million to the pension plans. |
EMPLOYEE_BENEFIT_PLANS_Pension
EMPLOYEE BENEFIT PLANS (Pension and Other Retiree Benefit Related Balance Sheet Amounts) (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Pension Plan, Defined Benefit [Member] | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Pension Asset Included in Other Regulatory Assets | $117 | $71 |
Accrued Benefit Liability Included in Accrued Employee Expenses | -1 | -1 |
Accrued Benefit Liability Included in Pension and Other Retiree Benefits | -71 | -23 |
Accumulated Other Comprehensive Loss (related to SERP) | 5 | 2 |
Net Total Amount On Balance Sheet | 50 | 49 |
Other Retiree Benefits [Member] | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Regulatory Pension Asset Included in Other Regulatory Assets | 9 | 4 |
Accrued Benefit Liability Included in Accrued Employee Expenses | -2 | -2 |
Accrued Benefit Liability Included in Pension and Other Retiree Benefits | -67 | -62 |
Accumulated Other Comprehensive Loss (related to SERP) | 0 | 0 |
Net Total Amount On Balance Sheet | ($60) | ($60) |
EMPLOYEE_BENEFIT_PLANS_Change_
EMPLOYEE BENEFIT PLANS (Change in Projected Benefit Obligation and Plan Assets and Reconciliation of Funded Status) (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Pension Plan, Defined Benefit [Member] | |||||||
Change in Projected Benefit Obligation | |||||||
Benefit Obligation at Beginning of Year | $407 | $330 | $330 | $357 | |||
Actuarial (Gain) Loss | 67 | -35 | |||||
Interest Cost | 4 | 4 | 16 | 14 | 15 | ||
Service Cost | 3 | 2 | 10 | 11 | 9 | ||
Benefits Paid | -16 | -17 | |||||
Projected Benefit Obligation at End of Year | 407 | 330 | 357 | ||||
Change in Plan Assets | |||||||
Fair Value Beginning Balance | 335 | 307 | 307 | 275 | |||
Actual Return on Plan Assets | 35 | 27 | |||||
Benefits Paid | -16 | -17 | |||||
Employer Contributions | 9 | [1] | 22 | [1] | |||
Fair Value Ending Balance | 335 | 307 | 275 | ||||
Funded Status at End of Year | -72 | -23 | |||||
Other Retiree Benefits [Member] | |||||||
Change in Projected Benefit Obligation | |||||||
Benefit Obligation at Beginning of Year | 81 | 74 | 74 | 77 | |||
Actuarial (Gain) Loss | 5 | -5 | |||||
Interest Cost | 1 | 0 | 3 | 3 | 3 | ||
Service Cost | 1 | 1 | 4 | 3 | 3 | ||
Benefits Paid | -5 | -4 | |||||
Projected Benefit Obligation at End of Year | 81 | 74 | 77 | ||||
Change in Plan Assets | |||||||
Fair Value Beginning Balance | 12 | 10 | 10 | 7 | |||
Actual Return on Plan Assets | 1 | 1 | |||||
Benefits Paid | -5 | -4 | |||||
Employer Contributions | 6 | [1] | 6 | [1] | |||
Fair Value Ending Balance | 12 | 10 | 7 | ||||
Funded Status at End of Year | ($69) | ($64) | |||||
[1] | In 2015, TEP expects to contribute $23 million to the pension plans. |
EMPLOYEE_BENEFIT_PLANS_Expecte
EMPLOYEE BENEFIT PLANS (Expected Pension Contributions For Next Year) (Detail) (Scenario, Forecast [Member], Pension Plan, Defined Benefit [Member], USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2015 |
Scenario, Forecast [Member] | Pension Plan, Defined Benefit [Member] | |
Funded Status And Amount Recognized In Balance Sheet And Statement Of Operations [Line items] | |
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year | $23 |
EMPLOYEE_BENEFIT_PLANS_Compone1
EMPLOYEE BENEFIT PLANS (Components of Regulatory Assets and Accumulated Other Comprehensive Loss Not Recognized as Net Periodic Benefit Cost) (Detail) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Pension Plan, Defined Benefit [Member] | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Net Loss | $118 | $74 |
Prior Service Cost (Benefit) | 4 | 0 |
Other Retiree Benefits [Member] | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Net Loss | 11 | 6 |
Prior Service Cost (Benefit) | ($2) | ($2) |
EMPLOYEE_BENEFIT_PLANS_Informa
EMPLOYEE BENEFIT PLANS (Information for Pension Plans with Accumulated Benefit Obligations in Excess of Pension Plan Assets) (Detail) (Pension Plan, Defined Benefit [Member], USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Pension Plan, Defined Benefit [Member] | ||
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items] | ||
Accumulated Benefit Obligation at End of Year | $365 | $13 |
Fair Value of Plan Assets at End of Year | $335 | $0 |
Changes_in_Regulatory_Assets_a
(Changes in Regulatory Assets and Accumulated Comprehensive Income) (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Regulatory Asset [Member] | Pension Plan, Defined Benefit [Member] | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Other Comprehensive Loss (Income), Pension and Other Postretirement Benefit Plans, Net Unamortized Loss (Gain) Arising During Period, before Tax | $49 | ($42) | $28 |
Actuarial Loss Amortization | -3 | -8 | -7 |
Total Recognized (Gain) Loss | 46 | -50 | 21 |
Regulatory Asset [Member] | Other Retiree Benefits [Member] | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Other Comprehensive Loss (Income), Pension and Other Postretirement Benefit Plans, Net Unamortized Loss (Gain) Arising During Period, before Tax | 5 | -6 | 2 |
Accumulated Other Comprehensive Loss | Pension Plan, Defined Benefit [Member] | |||
Pension Plans, Postretirement and Other Employee Benefits [Line Items] | |||
Other Comprehensive Loss (Income), Pension and Other Postretirement Benefit Plans, Net Unamortized Loss (Gain) Arising During Period, before Tax | 3 | -1 | 1 |
Actuarial Loss Amortization | 0 | 0 | 0 |
Total Recognized (Gain) Loss | $3 | ($1) | $1 |
EMPLOYEE_BENEFIT_PLANS_Weighte
EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Benefit Obligations) (Detail) | Dec. 31, 2014 | Dec. 31, 2013 |
Pension Plan, Defined Benefit [Member] | ||
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31, | ||
Rate of Compensation Increase | 3.00% | 3.00% |
Pension Plan, Defined Benefit [Member] | Minimum [Member] | ||
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31, | ||
Discount Rate | 4.10% | 5.00% |
Pension Plan, Defined Benefit [Member] | Maximum [Member] | ||
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31, | ||
Discount Rate | 4.20% | 5.10% |
Other Retiree Benefits [Member] | ||
Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31, | ||
Discount Rate | 3.90% | 4.70% |
EMPLOYEE_BENEFIT_PLANS_Weighte1
EMPLOYEE BENEFIT PLANS (Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost) (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Pension Plan, Defined Benefit [Member] | |||
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost | |||
Rate of Compensation Increase | 3.00% | 3.00% | 3.00% |
Expected Return on Plan Assets | 7.00% | 7.00% | 7.00% |
Pension Plan, Defined Benefit [Member] | Minimum [Member] | |||
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost | |||
Discount Rate | 5.00% | 4.10% | 4.90% |
Pension Plan, Defined Benefit [Member] | Maximum [Member] | |||
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost | |||
Discount Rate | 5.10% | 4.10% | 5.00% |
Other Retiree Benefits [Member] | |||
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost | |||
Discount Rate | 4.70% | 3.80% | 4.70% |
Expected Return on Plan Assets | 7.00% | 7.00% | 7.00% |
EMPLOYEE_BENEFIT_PLANS_Assumed
EMPLOYEE BENEFIT PLANS (Assumed Health Care Cost Trend Rates) (Detail) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Compensation and Retirement Disclosure [Abstract] | ||
Health Care Cost Trend Rate Assumed for Next Year | 6.70% | 6.70% |
Ultimate Health Care Cost Trend Rate Assumed | 4.50% | 4.50% |
Year that the Rate Reaches the Ultimate Trend Rate | 2027 | 2027 |
EMPLOYEE_BENEFIT_PLANS_OnePerc
EMPLOYEE BENEFIT PLANS (One-Percentage-Point Change in Assumed Health Care Cost Trend Rates) (Detail) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2014 |
Disclosure Employee Benefit Plans One Percentage Point Change In Assumed Health Care Cost Trend Rates [Abstract] | |
Effect of one percentage point increase on service and interest cost components | $1 |
Effect of one percentage point decrease on service and interest cost components | 1 |
Effect on Retiree Benefit Obligation, One-Percentage-Point Increase | 7 |
Effect on Retiree Benefit Obligation, One-Percentage-Point Decrease | $6 |
EMPLOYEE_BENEFIT_PLANS_Percent
EMPLOYEE BENEFIT PLANS (Percentage of Pension Plan Assets By Asset Category) (Detail) (Pension Plan, Defined Benefit [Member]) | Dec. 31, 2014 | Dec. 31, 2013 |
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 100.00% | 100.00% |
Equity Securities | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 48.00% | 50.00% |
Fixed Income | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 43.00% | 40.00% |
Real Estate | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 7.00% | 7.00% |
Other | ||
Pension And Other Employee Benefit Plans [Line Items] | ||
Pension plan assets allocation | 2.00% | 3.00% |
EMPLOYEE_BENEFIT_PLANS_Fair_Va
EMPLOYEE BENEFIT PLANS (Fair Value Measurements of Pension Plan Assets By Level) (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | |||
Level 3 [Member] | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | $23 | $21 | $19 |
Level 3 [Member] | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 16 | 14 | 13 |
Level 3 [Member] | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 7 | 7 | 6 |
Pension Plan, Defined Benefit [Member] | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 335 | 307 | 275 |
Pension Plan, Defined Benefit [Member] | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 1 | 1 | |
Pension Plan, Defined Benefit [Member] | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 82 | 76 | |
Pension Plan, Defined Benefit [Member] | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 17 | 16 | |
Pension Plan, Defined Benefit [Member] | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 61 | 62 | |
Pension Plan, Defined Benefit [Member] | Fixed Income | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 143 | 124 | |
Pension Plan, Defined Benefit [Member] | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 24 | 21 | |
Pension Plan, Defined Benefit [Member] | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 7 | 7 | |
Pension Plan, Defined Benefit [Member] | Level 1 [Member] | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 1 | 1 | |
Pension Plan, Defined Benefit [Member] | Level 1 [Member] | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 1 | 1 | |
Pension Plan, Defined Benefit [Member] | Level 1 [Member] | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 1 [Member] | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 1 [Member] | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 1 [Member] | Fixed Income | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 1 [Member] | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 1 [Member] | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 311 | 285 | |
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 82 | 76 | |
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 17 | 16 | |
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 61 | 62 | |
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Fixed Income | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 143 | 124 | |
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 8 | 7 | |
Pension Plan, Defined Benefit [Member] | Level 2 [Member] | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 23 | 21 | |
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | Cash Equivalents | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | United States Large Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | United States Small Cap | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | Non-United States | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | Fixed Income | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 0 | 0 | |
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | Real Estate | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | 16 | 14 | |
Pension Plan, Defined Benefit [Member] | Level 3 [Member] | Private Equity | |||
Pension And Other Employee Benefit Plans [Line Items] | |||
Fair value measurements of plan assets | $7 | $7 |
EMPLOYEE_BENEFIT_PLANS_Reconci
EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Fair Value of Level III Assets) (Detail) (Level 3 [Member], USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items] | ||
Fair Value Beginning Balance | $21 | $19 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 3 | 2 |
Purchases, Sales, and Settlements | -1 | |
Fair Value Ending Balance | 23 | 21 |
Private Equity | ||
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items] | ||
Fair Value Beginning Balance | 7 | 6 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 1 | 1 |
Purchases, Sales, and Settlements | -1 | |
Fair Value Ending Balance | 7 | 7 |
Real Estate | ||
Schedule Of Reconciliation Of Changes In Fair Value Of Assets And Liabilities [Line Items] | ||
Fair Value Beginning Balance | 14 | 13 |
Actual Return on Plan Assets: | ||
Assets Held at Reporting Date | 2 | 1 |
Purchases, Sales, and Settlements | 0 | |
Fair Value Ending Balance | $16 | $14 |
EMPLOYEE_BENEFIT_PLANS_Target_
EMPLOYEE BENEFIT PLANS (Target Allocation Percentages for Major Categories of Plan Assets) (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Pension Plan, Defined Benefit [Member] | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 100.00% |
Pension Plan, Defined Benefit [Member] | Fixed Income | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 41.00% |
Pension Plan, Defined Benefit [Member] | United States Large Cap | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 24.00% |
Pension Plan, Defined Benefit [Member] | Non-United States Developed | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 15.00% |
Pension Plan, Defined Benefit [Member] | Real Estate | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 8.00% |
Pension Plan, Defined Benefit [Member] | United States Small Cap | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 5.00% |
Pension Plan, Defined Benefit [Member] | Non-United States Emerging | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 5.00% |
Pension Plan, Defined Benefit [Member] | Private Equity | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 2.00% |
Pension Plan, Defined Benefit [Member] | Cash Equivalents | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 0.00% |
Other Retiree Benefits [Member] | VEBA Trust [Member] | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 100.00% |
Other Retiree Benefits [Member] | Fixed Income | VEBA Trust [Member] | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 38.00% |
Other Retiree Benefits [Member] | United States Large Cap | VEBA Trust [Member] | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 39.00% |
Other Retiree Benefits [Member] | Non-United States Developed | VEBA Trust [Member] | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 7.00% |
Other Retiree Benefits [Member] | Real Estate | VEBA Trust [Member] | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 0.00% |
Other Retiree Benefits [Member] | United States Small Cap | VEBA Trust [Member] | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 5.00% |
Other Retiree Benefits [Member] | Non-United States Emerging | VEBA Trust [Member] | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 9.00% |
Other Retiree Benefits [Member] | Private Equity | VEBA Trust [Member] | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 0.00% |
Other Retiree Benefits [Member] | Cash Equivalents | VEBA Trust [Member] | |
Pension And Other Employee Benefit Plans [Line Items] | |
Target allocation percentage of plan assets | 2.00% |
EMPLOYEE_BENEFIT_PLANS_Future_
EMPLOYEE BENEFIT PLANS (Future Benefit Payments) (Detail) (USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Pension Plan, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |
2015 | $17 |
2016 | 17 |
2017 | 19 |
2018 | 20 |
2019 | 21 |
Years 2020-2024 | 121 |
Other Retiree Benefits [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items] | |
2015 | 5 |
2016 | 5 |
2017 | 5 |
2018 | 5 |
2019 | 6 |
Years 2020-2024 | $33 |
SUPPLEMENTAL_CASH_FLOW_INFORMA2
SUPPLEMENTAL CASH FLOW INFORMATION (Cash Payments) (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Supplemental Cash Flow Elements [Abstract] | |||
Interest Paid, Net of Amounts Capitalized | ($82,653) | ($52,589) | ($52,125) |
Income Taxes Paid | $0 | $0 | ($1,796) |
SUPPLEMENTAL_CASH_FLOW_INFORMA3
SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Detail) (USD $) | 12 Months Ended | 1 Months Ended | |||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Apr. 30, 2013 | Oct. 31, 2013 | Apr. 30, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Sep. 30, 2012 | |
Construction in Progress Expenditures Incurred but Not yet Paid | $5,138,000 | $4,995,000 | $4,813,000 | ||||||
Net Cost Of Removal Of Interim Retirements | 12,128,000 | 25,182,000 | 35,983,000 | ||||||
Change In Capital Lease Obligations | 1,107,000 | 9,039,000 | 11,967,000 | ||||||
Asset Retirement Obligation, Liabilities Incurred | 4,117,000 | 8,064,000 | 789,000 | ||||||
Unsecured Debt [Member] | |||||||||
Debt face amount | 150,000,000 | 91,000,000 | 150,000,000 | ||||||
Debt extinguishment | 193,000,000 | 91,000,000 | |||||||
Unsecured Debt [Member] | Variable Rate Bonds [Member] | |||||||||
Debt face amount | 100,000,000 | ||||||||
Unsecured Debt [Member] | Pima County IDB [Member] | |||||||||
Debt extinguishment | 16,000,000 | ||||||||
Unsecured Debt [Member] | Apache County IDB [Member] | |||||||||
Debt extinguishment | 177,000,000 | ||||||||
Springerville Unit One Lease [Member] | |||||||||
Increase in Utility Plant under Capital Lease | 55,000,000 | ||||||||
Increase in Capital Lease Obligation | 55,000,000 | ||||||||
Springerville Coal Handling Facilities Lease [Member] | |||||||||
Increase in Utility Plant under Capital Lease | 109,000,000 | ||||||||
Increase in Capital Lease Obligation | $109,000,000 |
INCOME_TAXES_INCOME_TAXES_Diff
INCOME TAXES INCOME TAXES (Differences between Income Tax Expense and Amount Obtained by Multiplying Pre-Tax Income by U.S. Statutory Federal Income Tax Rate) (Detail) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2013 | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Disclosure Income Taxes Differences Between Income Tax Expense And Amount Obtained By Multiplying Pre Tax Income By U S Statutory Federal Income Tax Rate [Abstract] | ||||||
Statutory tax rate | 35.00% | |||||
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount | $56,000,000 | $52,000,000 | $37,000,000 | |||
State Income Tax Expense, Net of Federal Deduction | 7,000,000 | 7,000,000 | 5,000,000 | |||
Federal/State Tax Credits | -5,000,000 | -2,000,000 | -1,000,000 | |||
Allowance for Funds Used During Construction Income Tax Difference | -2,000,000 | -1,000,000 | -1,000,000 | |||
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount | 0 | 2,000,000 | 0 | |||
Investment Tax Credit Basis Difference | -11,000,000 | 0 | -11,000,000 | 0 | ||
Other | 2,000,000 | 1,000,000 | -1,000,000 | |||
Income Tax Expense (Benefit) | $4,339,000 | $5,338,000 | $57,911,000 | $47,986,000 | $39,109,000 |
INCOME_TAXES_INCOME_TAXES_Inco
INCOME TAXES INCOME TAXES (Income Tax Expense Included in Income Statements) (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Current Tax Expense (Benefit) | |||||
Federal | ($1,000,000) | ($8,000,000) | ($4,000,000) | ||
State | 0 | -2,000,000 | -2,000,000 | ||
Total | -1,000,000 | -10,000,000 | -6,000,000 | ||
Deferred Tax Expense (Benefit) | |||||
Federal | 54,000,000 | 47,000,000 | 38,000,000 | ||
Investment Tax Credit | -4,000,000 | -1,000,000 | 0 | ||
State | 9,000,000 | 12,000,000 | 7,000,000 | ||
Deferred Income Tax Expense (Benefit) | 59,000,000 | 58,000,000 | 45,000,000 | ||
Income Tax Expense (Benefit) | $4,339,000 | $5,338,000 | $57,911,000 | $47,986,000 | $39,109,000 |
INCOME_TAXES_INCOME_TAXES_The_
INCOME TAXES INCOME TAXES (The Significant Components of Deferred Income Tax Assets and Liabilities) (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Gross Deferred Income Tax Assets | ||
Capital Lease Obligations | $96 | $127 |
Net Operating Loss Carryforwards | 187 | 104 |
Customer Advances and Contributions in Aid of Construction | 19 | 19 |
Alternative Minimum Tax Credit | 24 | 24 |
Accrued Postretirement Benefits | 23 | 23 |
Emission Allowance Inventory | 10 | 10 |
Investment Tax Credit Carryforward | 31 | 6 |
Other | 54 | 38 |
Gross Deferred Income Tax Assets | 444 | 351 |
Deferred Tax Assets Valuation Allowance | -2 | -2 |
Gross Deferred Income Tax Liabilities | ||
Plant - Net | -699 | -615 |
Capital Lease Assets - Net | -74 | -47 |
Pensions | -27 | -22 |
PPFAC | -8 | -2 |
Other | -24 | -20 |
Deferred Tax Liabilities, Gross | -832 | -706 |
Deferred Tax Liabilities, Net | ($390) | ($357) |
INCOME_TAXES_INCOME_TAXES_Bala
INCOME TAXES INCOME TAXES (Balance Sheets Display Net Deferred Income Tax Liability) (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Disclosure Income Taxes Balance Sheets Display Net Deferred Income Tax Liability [Abstract] | ||
Deferred Income Taxes - Current Assets | $102 | $71 |
Deferred Tax Liabilities, Gross, Noncurrent | -492 | -428 |
Deferred Tax Liabilities, Net | ($390) | ($357) |
INCOME_TAXES_INCOME_TAXES_Addi
INCOME TAXES INCOME TAXES (Additional Information) (Detail) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Disclosure [Abstract] | ||
Deferred Tax Asset Valuation Allowance | $2,000,000 | $2,000,000 |
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | 0 | |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 0 | |
Unrecognized Tax Benefits, Interest on Income Taxes Expense | 0 | 1,000,000 |
Reductions Based on Settlements with Tax Authorities | 0 | -22,000,000 |
Change In Deferred Tax Liabilities And Deferred Tax Assets Related To Tangible Property | $22,000,000 |
INCOME_TAXES_Summary_of_Tax_Ca
INCOME TAXES (Summary of Tax Carryforwards) (Detail) (USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Internal Revenue Service (IRS) [Member] | |
Income Tax Contingency [Line Items] | |
Operating Loss Carryforwards | $507 |
Tax Credits | 24 |
Investment Tax Credits | 31 |
State Tax Jurisdiction [Member] | |
Income Tax Contingency [Line Items] | |
Operating Loss Carryforwards | 237 |
Tax Credits | $8 |
INCOME_TAXES_Operating_Loss_Ca
INCOME TAXES Operating Loss Carryforwards, Expiration Date (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Minimum [Member] | Internal Revenue Service (IRS) [Member] | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards, Expiration Date | 31-Dec-31 |
Investment Tax Credits, Expiration Date | 31-Dec-32 |
Alternative Minimum Tax Credit Carryforwards, Expiration Date | None |
Minimum [Member] | State Tax Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards, Expiration Date | 31-Dec-16 |
Investment Tax Credits, Expiration Date | 31-Dec-16 |
Maximum [Member] | Internal Revenue Service (IRS) [Member] | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards, Expiration Date | 31-Dec-34 |
Investment Tax Credits, Expiration Date | 31-Dec-34 |
Alternative Minimum Tax Credit Carryforwards, Expiration Date | None |
Maximum [Member] | State Tax Jurisdiction [Member] | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards, Expiration Date | 31-Dec-34 |
Investment Tax Credits, Expiration Date | 31-Dec-19 |
INCOME_TAXES_Uncertain_Tax_Pos
INCOME TAXES (Uncertain Tax Positions) (Detail) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Uncertain Tax Positions [Abstract] | ||
Unrecognized Tax Benefits | $2 | $23 |
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions | 2 | 1 |
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 0 | -22 |
Unrecognized Tax Benefits | $4 | $2 |
QUARTERLY_FINANCIAL_DATA_Summa
QUARTERLY FINANCIAL DATA - Summary of Quarterly Financial Data (Detail) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||||
In Thousands, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Disclosure Quarterly Financial Data Summary Of Quarterly Financial Data [Abstract] | ||||||||||||
Operating Revenue | $273,392 | $305,359 | $387,411 | $321,618 | $255,513 | $273,437 | $371,239 | $304,263 | $247,751 | $1,269,901 | $1,196,690 | $1,161,660 |
Operating Income | 28,193 | 34,138 | 84,898 | 79,653 | 31,999 | 31,014 | 123,177 | 53,433 | 22,747 | 230,688 | 230,371 | 200,487 |
Net Income (Loss) | $9,429 | $14,797 | $39,644 | $38,725 | $9,172 | $4,910 | $64,167 | $30,787 | $1,478 | $102,338 | $101,342 | $65,470 |
SCHEDULE_II_Valuation_and_Qual
SCHEDULE II - Valuation and Qualifying Accounts (Detail) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Allowance for Doubtful Accounts [Member] | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Beginning Balance | $5 | $5 | $14 | |
Additions-Charged to Income | 2 | 2 | 3 | |
Deductions | 2 | 2 | 12 | |
Ending Balance | 5 | 5 | 5 | |
Other Reserves | ||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||
Beginning Balance | 4 | |||
Ending Balance | $5 | $4 | $8 | $4 |