Tucson Electric Power 10-Q 3 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 02, 2016
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
Entity Registrant Name	TUCSON ELECTRIC POWER COMPANY
Entity Central Index Key	100,122
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		32,139,434

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS) (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating Revenues
Electric Retail Sales	$ 203,953	$ 201,622
Electric Wholesale Sales	14,413	41,462
Other Revenues	25,113	30,308
Total Operating Revenues	243,479	273,392
Operating Expenses
Fuel	62,678	70,569
Purchased Power	17,740	30,522
Transmission and Other PPFAC Recoverable Costs	5,178	4,707
Increase (Decrease) to Reflect PPFAC Recovery Treatment	6,795	3,249
Total Fuel and Purchased Power	92,391	109,047
Operations and Maintenance	84,999	82,645
Depreciation	35,632	34,733
Amortization	5,476	5,562
Taxes Other Than Income Taxes	13,030	13,212
Total Operating Expenses	231,528	245,199
Operating Income	11,951	28,193
Other Income (Deductions)
Interest Income	38	29
Other Income	1,393	622
Other Expense	(423)	(462)
Appreciation (Depreciation) in Value of Investments	200	780
Total Other Income (Deductions)	1,208	969
Interest Expense
Long-Term Debt	15,491	14,410
Capital Leases	858	1,004
Other Interest Expense	123	434
Interest Capitalized	(464)	(454)
Total Interest Expense	16,008	15,394
Income (Loss) Before Income Taxes	(2,849)	13,768
Income Tax Expense (Benefit)	(2,147)	4,339
Net Income (Loss)	$ (702)	$ 9,429

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ (702)	$ 9,429
Other Comprehensive Income (Loss)
Net Changes in Fair Value of Cash Flow Hedges:	9	14
Supplemental Executive Retirement Plan Adjustments:	56	60
Total Other Comprehensive Income (Loss), Net of Tax	65	74
Total Comprehensive Income (Loss)	$ (637)	$ 9,503

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Tax (Expense) Benefit related to Change in Fair Value of Cash Flow Hedges	$ 6	$ 12
Tax (Expense) Benefit related to Supplemental Executive Retirement Plan Adjustment	$ 35	$ 37

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Cash Flows [Abstract]
Net Income (Loss)	$ (702)	$ 9,429
Adjustments to Reconcile Net Income (Loss) To Net Cash Flows from Operating Activities:
Depreciation Expense	35,632	34,733
Amortization Expense	5,476	5,562
Amortization of Debt Issuance Costs	726	716
Provision for Springerville Unit 1 - Third-Party Owners Unrealized Revenue	6,307	5,521
Use of Renewable Energy Credits for Compliance	3,518	7,210
Deferred Income Taxes	(2,149)	4,339
Pension and Retiree Expense	3,835	4,647
Pension and Retiree Funding	(1,582)	(2,624)
Share-Based Compensation Expense	779	656
Allowance for Equity Funds Used During Construction	(1,171)	(343)
Refunds Related to Transmission Contracts	(13,314)	0
Changes in Current Assets and Current Liabilities
Accounts Receivable	23,473	10,503
Materials, Supplies, and Fuel Inventory	2,593	(4,239)
Regulatory Assets	(5,680)	(753)
Accounts Payable and Accrued Charges	150	2,014
Regulatory Liabilities	5,294	(7,112)
Other, Net	4,917	(2,771)
Net Cash Flows—Operating Activities	94,730	67,488
Cash Flows from Investing Activities
Capital Expenditures	(72,837)	(99,291)
Purchase of Springerville Unit 1 Lease Assets	0	(45,753)
Purchase of Intangibles - Renewable Energy Credits	(7,701)	(6,325)
Contributions in Aid of Construction	(456)	959
Net Cash Flows—Investing Activities	(80,994)	(150,410)
Cash Flows from Financing Activities
Proceeds from Borrowings Under Revolving Credit Facilities	0	15,000
Repayments of Borrowings Under Revolving Credit Facilities	0	(100,000)
Proceeds from Borrowings Under Term Loan	0	130,000
Repayments of Borrowings Under Term Loan	0	(130,000)
Proceeds from Issuance of Long-Term Debt	0	299,019
Repayments of Long-Term Debt	0	(130,000)
Payments of Capital Lease Obligations	(9,039)	(8,394)
Payment of Debt Issue/Retirement Costs	0	(2,372)
Other, Net	30	847
Net Cash Flows—Financing Activities	(9,009)	74,100
Net Increase (Decrease) in Cash and Cash Equivalents	4,727	(8,822)
Cash and Cash Equivalents, Beginning of Period	55,684	74,170
Cash and Cash Equivalents, End of Period	$ 60,411	$ 65,348

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Utility Plant
Plant in Service	$ 5,574,816	$ 5,618,435
Utility Plant Under Capital Leases	131,705	131,705
Construction Work in Progress	125,959	102,028
Total Utility Plant	5,832,480	5,852,168
Less Accumulated Depreciation and Amortization	(2,170,055)	(2,194,301)
Less Accumulated Amortization of Capital Lease Assets	(100,857)	(99,638)
Total Utility Plant, Net	3,561,568	3,558,229
Investments and Other Property	39,965	39,569
Current Assets
Cash and Cash Equivalents	60,411	55,684
Accounts Receivable, Net	105,065	136,710
Fuel Inventory	31,802	34,600
Materials and Supplies	92,594	94,003
Regulatory Assets	62,406	51,841
Derivative Instruments	1,153	1,808
Assets Held for Sale, Net	21,550	21,550
Other	13,963	25,876
Total Current Assets	388,944	422,072
Regulatory and Other Assets
Regulatory Assets	214,717	212,312
Derivative Instruments	348	430
Other	30,314	16,866
Total Regulatory and Other Assets	245,379	229,608
Total Assets	4,235,856	4,249,478
Capitalization
Common Stock (No Par Value, 75,000 Shares Authorized, 32,139 Shares Outstanding at March 31, 2016 and December 31, 2015)	1,296,539	1,296,539
Capital Stock Expense	(6,357)	(6,357)
Retained Earnings	188,615	189,317
Accumulated Other Comprehensive Loss	(4,499)	(4,564)
Total Common Stock Equity	1,474,298	1,474,935
Preferred Stock (No Par Value, 1,000 Shares Authorized, None Outstanding at March 31, 2016 and December 31, 2015)	0	0
Capital Lease Obligations	44,719	55,324
Long-Term Debt, Net	1,452,058	1,451,720
Total Capitalization	2,971,075	2,981,979
Current Liabilities
Current Obligations Under Capital Leases	15,239	14,114
Accounts Payable	81,927	86,274
Accrued Taxes Other than Income Taxes	47,865	37,577
Accrued Employee Expenses	20,759	27,718
Accrued Interest	12,686	14,246
Regulatory Liabilities	59,862	53,077
Customer Deposits	20,188	20,349
Derivative Instruments	14,461	12,174
Other	9,855	7,533
Total Current Liabilities	282,842	273,062
Regulatory and Other Liabilities
Deferred Income Taxes, Net	458,443	468,024
Regulatory Liabilities	302,367	307,286
Pension and Other Postretirement Benefits	120,996	120,336
Derivative Instruments	3,415	4,067
Other	96,718	94,724
Total Regulatory and Other Liabilities	$ 981,939	$ 994,437
Commitments and Contingencies
Total Capitalization and Other Liabilities	$ 4,235,856	$ 4,249,478

CONDENSED CONSOLIDATED BALANCE7

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Mar. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Common Stock, No Par Value ($ per share)	$ 0	$ 0
Common Stock, Shares Authorized	75,000,000	75,000,000
Common Stock, Shares, Outstanding	32,139,000	32,139,000
Preferred Stock, No Par Value ($ per share)	$ 0	$ 0
Preferred Stock, Shares Authorized	1,000,000	1,000,000
Preferred Stock, Shares Outstanding	0	0

CONDENSED CONSOLIDATED STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited) - USD ($) $ in Thousands	Total	Common Stock [Member]	Capital Stock Expense [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]
Balances at Dec. 31, 2014	$ 1,215,779	$ 1,116,539	$ (6,357)	$ 111,523	$ (5,926)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income (Loss)	9,429			9,429
Other Comprehensive Income (Loss), Net of Tax	74				74
Balances at Mar. 31, 2015	1,225,282	1,116,539	(6,357)	120,952	(5,852)
Balances at Dec. 31, 2015	1,474,935	1,296,539	(6,357)	189,317	(4,564)
Increase (Decrease) in Stockholder's Equity [Roll Forward]
Net Income (Loss)	(702)			(702)
Other Comprehensive Income (Loss), Net of Tax	65				65
Balances at Mar. 31, 2016	$ 1,474,298	$ 1,296,539	$ (6,357)	$ 188,615	$ (4,499)

NATURE OF OPERATIONS AND FINANC

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION	NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION Tucson Electric Power Company (TEP) is a regulated utility that generates, transmits, and distributes electricity to approximately 418,000 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). References in these notes to "we" and "our" are to TEP. BASIS OF PRESENTATION We prepared our condensed consolidated financial statements according to Generally Accepted Accounting Principles (GAAP) in the United States of America, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. The condensed consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stations and transmission facilities with both affiliated and non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded in Utility Plant on the 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 (Loss). These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the consolidated financial statements and footnotes in our 2015 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. Certain amounts from prior periods have been reclassified to conform to the current period presentation.

REGULATORY MATTERS

REGULATORY MATTERS	3 Months Ended
	Mar. 31, 2016
Regulated Operations [Abstract]
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. 2015 RATE CASE In November 2015 , TEP filed a general rate case with the ACC based on a test year ended June 30, 2015. The filing requests that new rates be implemented by January 1, 2017 . The key provisions of TEP's general rate case include: • a Base Rate increase of $110 million , or 12% , compared with adjusted test year revenues; • a 7.34% return on original cost rate base of $2.1 billion ; • a request to apply excess depreciation reserves against the unrecovered net book value (NBV) of the San Juan Generating Station (San Juan) Unit 2 and the H. Wilson Sundt Generating Station (Sundt) Coal Handling Facilities due to early retirement; • a request for authority to begin using the Third-Party Owners' portion of Springerville Generating Station (Springerville) Unit 1 that is available to TEP for dispatch to serve retail customers' needs and to recover the related operating costs through the Purchased Power and Fuel Adjustment Clause (PPFAC); and • rate design changes that would reduce the reliance on volumetric sales to recover fixed costs and a new net metering tariff that would ensure that customers who install distributed generation pay an equitable price for their electric service. TEP cannot predict the outcome of this proceeding or whether its rate request will be adopted by the ACC in whole or in part. COST RECOVERY MECHANISMS TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below. Purchased Power and Fuel Adjustment Clause TEP's PPFAC rate is adjusted annually each April 1st and goes into effect for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: (i) a forward component which attempts to recover or refund the difference between forecasted fuel costs and those embedded in the current PPFAC and fuel rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period. The table below presents TEP's PPFAC rates approved by the ACC: Period Cents per kWh May 2016 through March 2017 (1) 0.15 April 2015 through April 2016 0.68 October 2014 through March 2015 (2) 0.50 (1) In April 2016, the ACC approved the PPFAC rate adjustment. (2) The ACC approved a new rate effective October 2014. Energy Efficiency Standards TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency Standards (EE Standards). The EE Standards provide for a DSM surcharge for regulated utilities to recover from retail customers the costs to implement DSM programs as well as an annual performance incentive. TEP records its annual DSM performance incentive in the first quarter of each year, with $2 million recorded in 2016 and $3 million in 2015 related to performance in each respective prior calendar year. This performance incentive is included in Electric Retail Sales on the Condensed Consolidated Statements of Income (Loss). In February 2016, the ACC approved TEP’s 2016 energy efficiency implementation plan. Under the 2016 plan, TEP will recover approximately $14 million from retail customers and will offer customers new and existing DSM programs. Energy savings realized through the programs will count toward the EE Standards and the associated lost revenue will be partially recovered through the Lost Fixed Cost Recovery (LFCR). Lost Fixed Cost Recovery Mechanism The LFCR mechanism provides recovery of certain non-fuel costs that would go unrecovered due to lost retail kilowatt-hour (kWh) sales as a result of implementing ACC-approved energy efficiency programs and distributed generation targets. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to file an annual LFCR adjustment request with the ACC to recover the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of TEP's total retail revenues. TEP recorded a regulatory asset and recognized LFCR revenues of $5 million in the three months ended March 31, 2016 and $3 million in the three months ended March 31, 2015 . LFCR revenues are included in Electric Retail Sales on the Condensed Consolidated Statements of Income (Loss). Appellate Review of Rate Decisions In a 2015 appellate challenge to two ACC rate decisions regarding a water company, the Arizona Court of Appeals considered the issue of how the ACC should determine a utility’s “fair value,” as specified in the Arizona Constitution, in connection with authorizing recovery of costs through rate adjustors outside of a rate case. The Court reversed the ACC’s method of finding fair value in that case and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. In February 2016, the Arizona Supreme Court granted the ACC’s request for review of this decision. In March 2016, the Supreme Court heard oral arguments on this matter. If the Supreme Court upholds the decision without modification, certain TEP rate adjustors may be negatively affected which could have a significant impact on TEP’s ability to recover certain costs between rate cases. TEP filed a brief in support of the ACC’s petition to the Supreme Court for review of the Court of Appeals’ decision, but cannot predict the outcome of this matter. FERC MATTERS On April 21, 2016, the FERC issued an order (FERC Refund Order) relating to certain late-filed transmission service agreements (TSAs), which directs TEP to issue time value refunds to the relevant counterparties to these TSAs, in an amount up to $13 million . Refunds are due to these counterparties within 30 days from the issuance of the FERC Refund Order, and TEP must file a refund report with FERC within 30 days thereafter. TEP may appeal the FERC Refund Order within 60 days from the date issued. See Note 5 for additional information related to FERC compliance associated with transmission contracts. REGULATORY ASSETS AND LIABILITIES Regulatory assets are either being collected in rates designed to allow a regulated utility to recover its costs of providing services and an opportunity to earn a reasonable return on its investment (Retail Rates) or are expected to be collected through Retail Rates in a future period. With the exception of Springerville Unit 1 Leasehold Improvements - Third-Party Owners and Sundt Coal Handling Facilities, 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. With the exception of over-recovered PPFAC costs, TEP does not pay or accrue a return on regulatory liabilities. The regulatory assets and liabilities recorded in the Condensed Consolidated Balance Sheets are summarized below: (in millions) March 31, 2016 December 31, 2015 Remaining Recovery Period (years) Regulatory Assets Pension and Other Postretirement Benefits $ 118 $ 120 Various Final Mine Reclamation and Retiree Health Care Costs (1) 29 28 21 Property Tax Deferrals 22 21 1 Springerville Unit 1 Leasehold Improvements - Third-Party Owners (2) 20 21 7 Income Taxes Recoverable through Future Rates 19 26 Various LFCR 19 16 1 Sundt Coal Handling Facilities (3) 17 — Plant Life Derivatives (Note 8) 14 12 3 Other Regulatory Assets 19 20 Various Total Regulatory Assets 277 264 Less Current Portion 62 52 1 Total Non-Current Regulatory Assets $ 215 $ 212 Regulatory Liabilities Net Cost of Removal for Interim Retirements (4) $ 261 $ 264 Various Deferred Investment Tax Credits 32 32 Various Renewable Energy Standards (RES) 25 25 Various PPFAC 25 18 1 Other Regulatory Liabilities 19 21 Various Total Regulatory Liabilities 362 360 Less Current Portion 60 53 1 Total Non-Current Regulatory Liabilities $ 302 $ 307 (1) Final Mine Reclamation and Retiree Health Care Costs are recognized at future value. TEP will fully recover these costs through the PPFAC when paid. The majority of our final reclamation costs are expected to occur through 2037 . (2) Springerville Unit 1 Leasehold Improvements represent investments TEP made, previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover Springerville Unit 1 leasehold improvement costs over a 10 -year amortization period. (3) In June 2014, the Environmental Protection Agency (EPA) issued a final rule that would require TEP to either: (i) install, by mid-2017, Selective Non-Catalytic Reduction (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. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. Consistent with the 2013 Rate Order, TEP has requested authorization from the ACC to apply excess depreciation reserves against the unrecovered NBV in its 2015 Rate Case. (4) Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations (ARO) net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, generation plant, and general and intangible plant which are not yet expended.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	3 Months Ended
	Mar. 31, 2016
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including UniSource Energy Services, Inc. (UES), UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy Affiliates). These transactions include the sale and purchase of power and transmission services, common cost allocations, and the provision of corporate and other labor related services. The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) March 31, 2016 December 31, 2015 Receivables from Related Parties UNS Electric $ 3 $ 6 UNS Gas 1 1 Total Due from Related Parties $ 4 $ 7 Payables to Related Parties SES $ 2 $ 2 UNS Energy 1 2 UNS Electric — 2 Total Due to Related Parties $ 3 $ 6 The following table presents the related party transactions included in the Condensed Consolidated Statements of Income (Loss): Three Months Ended March 31, (in millions) 2016 2015 Goods and Services Provided by TEP to Affiliates Transmission Sales - UNS Electric (1) $ 1 $ 1 Wholesale Sales - UNS Electric (1) — 1 Common Costs - UNS Energy Affiliates (2) 3 3 Goods and Services Provided by Affiliates to TEP Supplemental Workforce - SES (3) 4 4 Corporate Services - UNS Energy (4) 2 1 (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC approved rates, through the Open Access Transmission Tariff (OATT). (2) Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. (3) SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management. (4) Costs for corporate services at UNS Energy include Fortis management fees, legal fees, and audit fees which are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 82% of UNS Energy's allocated costs. These costs included approximately $2 million and $1 million in Fortis management fees for the three months ended March 31, 2016 and 2015 , respectively. DIVIDEND PAID TEP did not declare or pay dividends in the first three months of 2016 or 2015 .

DEBT, CREDIT FACILITIES, AND CA

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS	DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS LONG-TERM DEBT There have been no significant changes to our debt or capital lease obligations from those reported in our 2015 Annual Report on Form 10-K, except as noted below. CAPITAL LEASE OBLIGATIONS Springerville Coal Handling Facilities In April 2015, upon the expiration of the lease term, TEP purchased an undivided ownership interest in the coal handling facilities at Springerville used by all four Springerville units (Springerville Coal Handling Facilities). With the completion of this purchase, Tri-State Generation and Transmission Association, Inc. (Tri-State) was obligated to either: (i) buy a 17.05% undivided interest in the facilities for approximately $24 million ; or (ii) continue to make payments to TEP for the use of the facilities. In March 2016, Tri-State notified TEP that it was exercising its option to purchase the undivided interest in the facilities. The Tri-State purchase is expected to close by the end of 2016. At March 31, 2016 , Tri-State's 17.05% undivided interest in the Springerville Coal Handling Facilities is classified as Assets Held for Sale on the Condensed Consolidated Balance Sheets. COVENANT COMPLIANCE At March 31, 2016 , we were in compliance with the terms of our credit and long-term debt agreements.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS In addition to those reported in our 2015 Annual Report on Form 10-K, TEP entered into the following long-term commitments through March 31, 2016 : (in millions) 2016 2017 2018 2019 2020 Thereafter Total Fuel, Including Transportation $ 21 $ 23 $ 24 $ 24 $ 23 $ 22 $ 137 Renewable Power Purchase Agreements 3 3 3 3 3 43 58 Total Purchase Commitments $ 24 $ 26 $ 27 $ 27 $ 26 $ 65 $ 195 Fuel, Including Transportation 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. In January 2016, the existing coal sale agreement terminated and a new Coal Supply Agreement (CSA) became effective. The new CSA is between San Juan Coal Company (SJCC) and Public Service Company of New Mexico (PNM) and continues through June 2022. TEP is not a party to the new CSA, but has minimum purchase obligations under restructured ownership agreements at San Juan. In April 2016, Peabody Energy Corp. (Peabody) filed for reorganization under Chapter 11 of the Bankruptcy Code. TEP has existing contracts with Peabody to supply coal from the El Segundo and Lee Ranch mines to Springerville and from the Kayenta mine to Navajo. TEP currently anticipates that it will continue to receive its contracted fuel from the El Segundo, Lee Ranch, and Kayenta coal mines. Renewable Power Purchase Agreements TEP enters into long-term renewable Power Purchase Agreements (PPA) which require TEP to purchase 100% of certain renewable energy generation facilities output once commercial operation status is achieved. In the first three months of 2016 , one of these facilities achieved commercial operation. The PPA expires in February 2036 . While TEP is not required to make payments under this agreement if power is not delivered, estimated future payments are included in the table above. CONTINGENCIES Legal Matters TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts and are described below. Claims Related to Springerville Generating Station Unit 1 On February 29, 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (Agreement). The Agreement provides that: (i) TEP will purchase the Third-Party Owners’ 50.5% undivided interest in Springerville Unit 1 for $85 million ; and (ii) the Third-Party Owners will pay TEP $12.5 million for operating costs related to Springerville Unit 1 incurred on behalf of the Third-Party Owners. Upon completion of the purchase, all outstanding disputes and pending litigation and arbitration proceedings between TEP and the Third-Party Owners will be dismissed with prejudice. The purchase of the Third-Party Owners' undivided interest in Springerville Unit 1 is subject to, among other things, approval from the FERC and satisfaction of other customary closing conditions. TEP expects the purchase to close in the second quarter of 2016. However, there is no assurance that the settlement will be finalized or that the litigation will not continue. Therefore, at this time 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 claims, TEP cannot determine estimates of the range of loss, if any, at this time. Should the litigation matters continue, TEP intends to continue vigorously defending itself against the claims asserted by the Third-Party Owners and to continue vigorously pursuing the claims it has asserted against the Owner Trustees and Co-Trustees. The following is the chronological history of the outstanding disputes and pending litigation and arbitration proceedings between TEP and the Third-Party Owners. In November 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 existing 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 in January 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. In February 2015, the FERC issued an order denying the Third-Party Owners complaint. In March 2015, the Third-Party Owners filed a request for rehearing in the FERC Action, which the FERC denied in October 2015. In December 2015, the Third-Party Owners appealed the FERC’s order denying the Third-Party Owners' complaint to the U.S. Court of Appeals for the Ninth Circuit. In December 2015, TEP filed an unopposed motion to intervene in the Ninth Circuit appeal. In December 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). In response to motions filed by TEP to dismiss various counts and compel arbitration of certain of the matters alleged, and the court’s subsequent ruling on the motions, the Third-Party Owners have amended the complaint three times, dropping certain of the allegations and raising others in the New York Action and in the arbitration proceeding described below. As amended, the New York Action alleges, among other things, that TEP failed to properly operate, maintain, and make capital investments in Springerville Unit 1 during the term of the leases and that TEP has breached the lease transaction documents by refusing to pay certain of the Third-Party Owners’ claimed expenses. The third amended complaint seeks $71 million in liquidated damages and direct and consequential damages in an amount to be determined at trial. The Third-Party Owners have also agreed to stay their claim that TEP has not agreed to wheel power and energy as required pending the outcome of the FERC Action. In November 2015, the Third-Party Owners filed a motion for summary judgment on their claim that TEP has failed to pay certain of the Third-Party Owners’ claimed expenses. In December 2014 and January 2015, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent notices to TEP that alleged that TEP had defaulted under the Third-Party Owners’ leases. The notices demanded that TEP pay liquidated damages totaling approximately $71 million . In letters to the Owner Trustees, TEP denied the allegations in the notices. In April 2015, TEP filed a demand for arbitration with the American Arbitration Association (AAA) seeking an award of the Owner Trustees and Co-Trustees' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. In June 2015, the Third-Party Owners filed a separate demand for arbitration with the AAA alleging, among other things, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired. The Third-Party Owners’ arbitration demand seeks declaratory judgments, damages in an amount to be determined by the arbitration panel and the Third-Party Owners’ fees and expenses. TEP and the Third-Party Owners have since agreed to consolidate their arbitration demands into one proceeding. In August 2015, the Third-Party Owners filed an amended arbitration demand adding claims that TEP has converted the Third-Party Owners’ water rights and certain emission reduction payments and that TEP is improperly dispatching the Third-Party Owners’ unscheduled Springerville Unit 1 power and capacity. In October 2015, the arbitration panel granted TEP’s motion for interim relief, ordering the Owner Trustees and Co-Trustees to pay TEP their pro-rata share of unreimbursed expenses and capital expenditures for Springerville Unit 1 during the pendency of the arbitration. The arbitration panel also denied the Third-Party Owners’ motion for interim relief which had requested that TEP be enjoined from dispatching the Third-Party Owners’ unscheduled Springerville Unit 1 power and capacity. TEP has been scheduling, when economical, the Third-Party Owners’ entitlement share of power from Springerville Unit 1, as permitted under the Springerville Unit 1 facility support agreement, since June 2015. In November 2015, TEP filed a petition to confirm the interim arbitration order in the Supreme Court of the State of New York naming the Owner Trustee and Co-Trustee as respondents. The petition seeks an order from the court confirming the interim arbitration order under the Federal Arbitration Act. In December 2015, the Owner Trustees filed an answer to the petition and a cross-motion to vacate the interim arbitration order. As of March 31, 2016 , TEP has billed the Third-Party Owners approximately $29 million for their pro-rata share of Springerville Unit 1 expenses and $6 million for their pro-rata share of capital expenditures, none of which had been paid as of May 2, 2016 . Claims Related to San Juan Generating Station 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 owns 50% of Units 1 and 2 at 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 predict the final outcome of the BLM’s proposed regulations. In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. 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. SJCC was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now proceeding. A stay in the matter has expired although the parties continue to engage in settlement negotiations. 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 May 2013, the New Mexico Taxation and Revenue Department (NMTRD) issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners Generating Station (Four Corners). TEP's share of the assessment is $1 million based on our ownership percentage. 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. In June 2015, the U.S. District Court ruled in favor of the Four Corners' participants. NMTRD filed an appeal of the decision in August 2015. TEP cannot predict the final outcome or timing of resolution of these claims. In March 2016, the coal supplier at Four Corners reached a final settlement agreement with NMTRD. TEP's share of the final settlement was less than $1 million . Navajo Generating Station Lease Amendment 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 in 2013 that would extend the lease from 2019 through 2044 . The participants in Navajo, including TEP, have not signed the lease amendment because certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations between the participants 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. Once the lease amendment becomes effective, the participants will be responsible for additional lease costs from the date the Navajo Nation signed the lease amendment. TEP owns 7.5% of Navajo. In the first three months of 2016 , TEP recorded additional estimated lease expense of less than $1 million with the expectation that the lease amendment will become effective. TEP's Condensed Consolidated Balance Sheets reflect a total lease amendment liability recorded in Regulatory and Other Liabilities—Other of $4 million at March 31, 2016 and $3 million at December 31, 2015 . 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 $42 million upon expiration of the coal supply agreements, which expire between 2019 and 2031 . TEP's Condensed Consolidated Balance Sheets reflect a total liability related to reclamation of $25 million at March 31, 2016 and December 31, 2015 . 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 expected inflation rate. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements. TEP’s PPFAC allows 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. FERC Compliance In 2015, TEP self-reported to the FERC Office of Enforcement (OE) that TEP had not timely filed certain FERC-jurisdictional agreements. At that time, TEP conducted a comprehensive internal review of its compliance with the FERC filing requirements (Compliance Review), and made necessary compliance filings with the FERC Office of Energy Market Regulation. This included the filing of several TEP TSAs entered into between 2003 and 2015 that contained certain deviations from TEP’s standard form of service agreement. The results of the Compliance Review were reported to OE, which is still reviewing the matter. On April 21, 2016, the FERC issued the FERC Refund Order relating to the late-filed TSAs, which directs TEP to issue time value refunds to the relevant counterparties to these TSAs, in an amount of up to $13 million . As specified in the FERC Refund Order, TEP is reviewing its calculations of the ordered refunds to determine if issuing the refunds would cause TEP to have provided service at a loss under each TSA, in which case the refund amount may be reduced. Refunds are due to the relevant counterparties within 30 days from the issuance of the FERC Refund Order, and TEP must file a refund report with the FERC within 30 days thereafter. TEP may appeal the FERC Refund Order within 60 days from the date issued. In March 2016, TEP recorded $13 million in Accounts Payable on the Condensed Consolidated Balance Sheets and in Electric Wholesale Sales as an offset to transmission revenues on the Condensed Consolidated Statements of Income (Loss) as a result of the FERC Refund Order. The FERC could also impose civil penalties on TEP as a result the OE review of the Compliance Review. At this time, TEP cannot predict the outcome of this matter or the range of potential penalties, if any. Performance Guarantees TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and the Luna Energy Facility (Luna). The participants in each of the generating stations, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, 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 participant. As of March 31, 2016 , there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expires in 2019 , San Juan in 2022, Four Corners in 2041, and Luna in 2046. Environmental Matters TEP is subject to federal, state, and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in material compliance with all applicable environmental laws and regulations.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	3 Months Ended
	Mar. 31, 2016
Compensation and Retirement Disclosure [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS Net periodic benefit plan cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended March 31, (in millions) 2016 2015 2016 2015 Service Cost $ 3 $ 3 $ 1 $ 1 Interest Cost 4 4 — 1 Expected Return on Plan Assets (6 ) (6 ) — — Amortization of Net Loss (Gain) 2 2 — — Net Periodic Benefit Cost $ 3 $ 3 $ 1 $ 2

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	3 Months Ended
	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	SUPPLEMENTAL CASH FLOW INFORMATION NON-CASH TRANSACTIONS Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows: Three Months Ended March 31, (in millions) 2016 2015 Accrued Capital Expenditures $ 14 $ 30 Net Cost of Removal of Interim Retirements (1) 3 6 (1) The non-cash net cost of removal of interim retirements represents an accrual for future AROs that does not impact earnings.

FAIR VALUE MEASUREMENTS AND DER

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	3 Months Ended
	Mar. 31, 2016
Disclosure Text Block [Abstract]
FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS	FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS 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. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented. FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Level 1 Level 2 Level 3 Total (in millions) March 31, 2016 Assets Cash Equivalents (1) $ 44 $ — $ — $ 44 Restricted Cash (1) 4 — — 4 Energy Derivative Contracts - No Regulatory Recovery (2) — — 1 1 Total Assets 48 — 1 49 Liabilities Energy Derivative Contracts - Regulatory Recovery (2) — (10 ) (4 ) (14 ) Interest Rate Swap (3) — (3 ) — (3 ) Total Liabilities — (13 ) (4 ) (17 ) Net Total Assets (Liabilities) $ 48 $ (13 ) $ (3 ) $ 32 (in millions) December 31, 2015 Assets Cash Equivalents (1) $ 33 $ — $ — $ 33 Restricted Cash (1) 4 — — 4 Energy Derivative Contracts - Regulatory Recovery (2) — 1 — 1 Energy Derivative Contracts - No Regulatory Recovery (2) — — 1 1 Total Assets 37 1 1 39 Liabilities Energy Derivative Contracts - Regulatory Recovery (2) — (10 ) (3 ) (13 ) Interest Rate Swap (3) — (3 ) — (3 ) Total Liabilities — (13 ) (3 ) (16 ) Net Total Assets (Liabilities) $ 37 $ (12 ) $ (2 ) $ 23 (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 Condensed Consolidated Balance Sheets. Restricted cash is included in Investments and Other Property on the Condensed Consolidated Balance Sheets. (2) Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. The valuation techniques are described below. (3) The Interest Rate Swap is valued using an income valuation approach based on the 6-month LIBOR and is included in Derivative Instruments on the Condensed Consolidated Balance Sheets. All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We present derivatives on a gross basis in the Condensed Consolidated Balance Sheets. The tables below present the potential offset of counterparty netting and cash collateral. Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) March 31, 2016 Derivative Assets Energy Derivative Contracts $ 1 $ — $ — $ 1 Derivative Liabilities Energy Derivative Contracts (14 ) — — (14 ) Interest Rate Swap (3 ) — — (3 ) (in millions) December 31, 2015 Derivative Assets Energy Derivative Contracts $ 2 $ 1 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (13 ) (1 ) — (12 ) Interest Rate Swap (3 ) — — (3 ) DERIVATIVE INSTRUMENTS We enter into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with our gas and purchased power requirements. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC. We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers. For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, or industry publications, and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe that the market information provided is reflective of market conditions as of the time and date indicated. Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, we apply adjustments based on historical price curve relationships, transmission, and line losses. We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data. The inputs and our assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We review the assumptions underlying our price curves monthly. Cash Flow Hedges We can enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. We have an interest rate swap agreement that expires January 2020 . We also had a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement which expired in September 2015 . The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $1 million . The realized losses from our cash flow hedges are less than $ 1 million for the three months ended March 31, 2016 and 2015, respectively. At March 31, 2016 , the total notional amount of our interest rate swap was $23 million . Energy Derivative Contracts - Regulatory Recovery We record unrealized gains and losses on energy purchase contracts that are recoverable through the PPFAC in the balance sheet as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statement or in the statement of other comprehensive income, as shown in following table: Three Months Ended March 31, (in millions) 2016 2015 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ (2 ) $ (6 ) Energy Derivative 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 June 2015, TEP entered into long-term power trading contracts that qualify as derivatives but do not qualify for regulatory recovery. The unrealized gains and losses on the long-term power trading contracts are recorded in the income statement, and 10% of any gains will be shared with ratepayers through the PPFAC, as realized. Derivative Volumes At March 31, 2016 , we have energy contracts that will settle through 2019 . The volumes associated with our energy contracts were as follows: March 31, 2016 December 31, 2015 Power Contracts GWh 1,282 1,752 Gas Contracts GBtu 15,165 17,214 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 of Range of Approach Assets Liabilities Unobservable Inputs Unobservable Input (in millions) March 31, 2016 Forward Power Contracts Market approach $ 1 $ (3 ) Market price per MWh $ 15.90 $ 29.90 Gas Option Contracts Option model — (1 ) Market price per MMBtu $ 1.50 $ 2.67 Gas volatility 34.3 % 46.0 % Level 3 Energy Contracts $ 1 $ (4 ) Valuation Fair Value of Range of Approach Assets Liabilities Unobservable Inputs Unobservable Input (in millions) December 31, 2015 Forward Power Contracts Market approach $ 1 $ (2 ) Market price per MWh $ 19.20 $ 31.35 Gas Option Contracts Option model — (1 ) Market price per MMBtu $ 2.17 $ 2.69 Gas volatility 31.0 % 58.3 % Level 3 Energy Contracts $ 1 $ (3 ) Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement. The following table presents a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy: Three Months Ended March 31, (in millions) 2016 2015 Beginning of Period $ (2 ) $ (9 ) Gains (Losses) Recorded to: (1) Regulatory Assets or Liabilities – Derivative Instruments (1 ) (2 ) Settlements — (1 ) End of Period $ (3 ) $ (12 ) (1) Includes gains (losses) attributable to the change in unrealized gains/(losses) relating to assets (liabilities) still held at the end of the period of $(1) million and $(3) million , for the three months ended March 31, 2016 and 2015 , respectively. CREDIT RISK The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value. We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits; 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 Letter(s) of Credit (LOC) to fully collateralize our exposure to these counterparties. We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts. Material adverse changes could trigger credit risk-related contingent features. At March 31, 2016 , the value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $23 million , compared with $20 million at December 31, 2015 . At March 31, 2016 TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on March 31, 2016 , TEP would have been required to post an additional $23 million of collateral of which $8 million relates to outstanding net payable balances for settled positions. FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments: • Borrowings under revolving credit facilities approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below. • 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 following table includes the face value and estimated fair value of our long-term debt: Fair Value Hierarchy Face Value Fair Value (in millions) March 31, 2016 December 31, 2015 March 31, 2016 December 31, 2015 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,466 $ 1,526 $ 1,529

RECENTLY ISSUED ACCOUNTING PRON

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	3 Months Ended
	Mar. 31, 2016
Disclosure Text Block [Abstract]
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS We consider the applicability and impact of all Accounting Standards Updates issued by the Financial Accounting Standards Board (FASB). The following updates have been issued, but have not yet been adopted by TEP. Updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position, results of operations, or disclosures. Revenue from Contracts with Customers 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. In July 2015, the FASB voted to defer the effective date of the revenue recognition standard by one year. We are required to adopt the new guidance for annual and interim periods beginning January 1, 2018. Retail sales of electricity based on regulator-approved tariff rates represent TEP's primary source of revenue. While it is expected that tariff-based sales to regulated customers are within the scope of the new standard, this question is being reviewed by the AICPA Financial Reporting Executive Committee. TEP is in the process of assessing its performance obligations in its wholesale contracts and identifying other contracts with customers. Classification and Measurement of Financial Instruments In January 2016, the FASB amended the guidance on the classification and measurement of financial instruments. Most notably, the new accounting standard update requires the following: • all equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and • financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset. TEP is required to adopt the new guidance for annual and interim periods beginning January 1, 2018. TEP is evaluating the impact of this guidance to our financial statements and disclosures. Leases In February 2016, the FASB issued an accounting standards update that will require the recognition of leased assets and liabilities by lessees for those leases classified as operating leases under previous GAAP. The standard is effective for periods beginning January 1, 2019 and is to be applied using a modified retrospective approach with practical expedient options; early adoption is permitted. TEP is evaluating the impact of this update to our financial statements and disclosures. Share-Based Compensation In March 2016, the FASB issued an accounting standards update that simplifies some provisions in stock compensation accounting. The update involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendment: • requires that all excess tax benefits and tax deficiencies for share-based payment awards be recognized as income tax expense or benefit in the income statement; • specifies presentation on the statement of cash flows, and • requires an accounting policy election to estimate the number of awards that are expected to vest or account for forfeitures when they occur. TEP is required to adopt the new guidance for annual and interim periods beginning January 1, 2017; early adoption is permitted. TEP is evaluating the impact of this update to our financial statements and disclosures.

NATURE OF OPERATIONS AND FINA18

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Policies)	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis Of Presentation	BASIS OF PRESENTATION We prepared our condensed consolidated financial statements according to Generally Accepted Accounting Principles (GAAP) in the United States of America, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. The condensed consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stations and transmission facilities with both affiliated and non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded in Utility Plant on the 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 (Loss). These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting and should be read in conjunction with the consolidated financial statements and footnotes in our 2015 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. Certain amounts from prior periods have been reclassified to conform to the current period presentation.

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	3 Months Ended
	Mar. 31, 2016
Regulated Operations [Abstract]
Purchased Power and Fuel Adjustment Clause	The table below presents TEP's PPFAC rates approved by the ACC: Period Cents per kWh May 2016 through March 2017 (1) 0.15 April 2015 through April 2016 0.68 October 2014 through March 2015 (2) 0.50 (1) In April 2016, the ACC approved the PPFAC rate adjustment. (2) The ACC approved a new rate effective October 2014.
Schedule of Regulatory Assets and Liabilities	egulatory assets and liabilities recorded in the Condensed Consolidated Balance Sheets are summarized below: (in millions) March 31, 2016 December 31, 2015 Remaining Recovery Period (years) Regulatory Assets Pension and Other Postretirement Benefits $ 118 $ 120 Various Final Mine Reclamation and Retiree Health Care Costs (1) 29 28 21 Property Tax Deferrals 22 21 1 Springerville Unit 1 Leasehold Improvements - Third-Party Owners (2) 20 21 7 Income Taxes Recoverable through Future Rates 19 26 Various LFCR 19 16 1 Sundt Coal Handling Facilities (3) 17 — Plant Life Derivatives (Note 8) 14 12 3 Other Regulatory Assets 19 20 Various Total Regulatory Assets 277 264 Less Current Portion 62 52 1 Total Non-Current Regulatory Assets $ 215 $ 212 Regulatory Liabilities Net Cost of Removal for Interim Retirements (4) $ 261 $ 264 Various Deferred Investment Tax Credits 32 32 Various Renewable Energy Standards (RES) 25 25 Various PPFAC 25 18 1 Other Regulatory Liabilities 19 21 Various Total Regulatory Liabilities 362 360 Less Current Portion 60 53 1 Total Non-Current Regulatory Liabilities $ 302 $ 307 (1) Final Mine Reclamation and Retiree Health Care Costs are recognized at future value. TEP will fully recover these costs through the PPFAC when paid. The majority of our final reclamation costs are expected to occur through 2037 . (2) Springerville Unit 1 Leasehold Improvements represent investments TEP made, previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover Springerville Unit 1 leasehold improvement costs over a 10 -year amortization period. (3) In June 2014, the Environmental Protection Agency (EPA) issued a final rule that would require TEP to either: (i) install, by mid-2017, Selective Non-Catalytic Reduction (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. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. Consistent with the 2013 Rate Order, TEP has requested authorization from the ACC to apply excess depreciation reserves against the unrecovered NBV in its 2015 Rate Case. (4) Net Cost of Removal for Interim Retirements represents an estimate of the cost of future asset retirement obligations (ARO) net of salvage value. These are amounts collected through revenue for the net cost of removal of interim retirements for transmission, distribution, generation plant, and general and intangible plant which are not yet expended.

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Table)	3 Months Ended
	Mar. 31, 2016
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets: (in millions) March 31, 2016 December 31, 2015 Receivables from Related Parties UNS Electric $ 3 $ 6 UNS Gas 1 1 Total Due from Related Parties $ 4 $ 7 Payables to Related Parties SES $ 2 $ 2 UNS Energy 1 2 UNS Electric — 2 Total Due to Related Parties $ 3 $ 6 The following table presents the related party transactions included in the Condensed Consolidated Statements of Income (Loss): Three Months Ended March 31, (in millions) 2016 2015 Goods and Services Provided by TEP to Affiliates Transmission Sales - UNS Electric (1) $ 1 $ 1 Wholesale Sales - UNS Electric (1) — 1 Common Costs - UNS Energy Affiliates (2) 3 3 Goods and Services Provided by Affiliates to TEP Supplemental Workforce - SES (3) 4 4 Corporate Services - UNS Energy (4) 2 1 (1) TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC approved rates, through the Open Access Transmission Tariff (OATT). (2) Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process. (3) SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management. (4) Costs for corporate services at UNS Energy include Fortis management fees, legal fees, and audit fees which are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 82% of UNS Energy's allocated costs. These costs included approximately $2 million and $1 million in Fortis management fees for the three months ended March 31, 2016 and 2015 , respectively.

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments	In addition to those reported in our 2015 Annual Report on Form 10-K, TEP entered into the following long-term commitments through March 31, 2016 : (in millions) 2016 2017 2018 2019 2020 Thereafter Total Fuel, Including Transportation $ 21 $ 23 $ 24 $ 24 $ 23 $ 22 $ 137 Renewable Power Purchase Agreements 3 3 3 3 3 43 58 Total Purchase Commitments $ 24 $ 26 $ 27 $ 27 $ 26 $ 65 $ 195

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	3 Months Ended
	Mar. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Components of Net Periodic Benefit Cost	Net periodic benefit plan cost includes the following components: Pension Benefits Other Postretirement Benefits Three Months Ended March 31, (in millions) 2016 2015 2016 2015 Service Cost $ 3 $ 3 $ 1 $ 1 Interest Cost 4 4 — 1 Expected Return on Plan Assets (6 ) (6 ) — — Amortization of Net Loss (Gain) 2 2 — — Net Periodic Benefit Cost $ 3 $ 3 $ 1 $ 2

SUPPLEMENTAL CASH FLOW INFORM23

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	3 Months Ended
	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures	Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows: Three Months Ended March 31, (in millions) 2016 2015 Accrued Capital Expenditures $ 14 $ 30 Net Cost of Removal of Interim Retirements (1) 3 6 (1) The non-cash net cost of removal of interim retirements represents an accrual for future AROs that does not impact earnings.

FAIR VALUE MEASUREMENTS AND D24

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Tables)	3 Months Ended
	Mar. 31, 2016
Disclosure Text Block [Abstract]
Financial Instruments Measured at Fair Value on Recurring Basis	The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Level 1 Level 2 Level 3 Total (in millions) March 31, 2016 Assets Cash Equivalents (1) $ 44 $ — $ — $ 44 Restricted Cash (1) 4 — — 4 Energy Derivative Contracts - No Regulatory Recovery (2) — — 1 1 Total Assets 48 — 1 49 Liabilities Energy Derivative Contracts - Regulatory Recovery (2) — (10 ) (4 ) (14 ) Interest Rate Swap (3) — (3 ) — (3 ) Total Liabilities — (13 ) (4 ) (17 ) Net Total Assets (Liabilities) $ 48 $ (13 ) $ (3 ) $ 32 (in millions) December 31, 2015 Assets Cash Equivalents (1) $ 33 $ — $ — $ 33 Restricted Cash (1) 4 — — 4 Energy Derivative Contracts - Regulatory Recovery (2) — 1 — 1 Energy Derivative Contracts - No Regulatory Recovery (2) — — 1 1 Total Assets 37 1 1 39 Liabilities Energy Derivative Contracts - Regulatory Recovery (2) — (10 ) (3 ) (13 ) Interest Rate Swap (3) — (3 ) — (3 ) Total Liabilities — (13 ) (3 ) (16 ) Net Total Assets (Liabilities) $ 37 $ (12 ) $ (2 ) $ 23 (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 Condensed Consolidated Balance Sheets. Restricted cash is included in Investments and Other Property on the Condensed Consolidated Balance Sheets. (2) Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. The valuation techniques are described below. (3) The Interest Rate Swap is valued using an income valuation approach based on the 6-month LIBOR and is included in Derivative Instruments on the Condensed Consolidated Balance Sheets.
Potential Offset of Counterparty Netting and Cash Collateral	All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We present derivatives on a gross basis in the Condensed Consolidated Balance Sheets. The tables below present the potential offset of counterparty netting and cash collateral. Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount Counterparty Netting of Energy Contracts Cash Collateral Received/Posted (in millions) March 31, 2016 Derivative Assets Energy Derivative Contracts $ 1 $ — $ — $ 1 Derivative Liabilities Energy Derivative Contracts (14 ) — — (14 ) Interest Rate Swap (3 ) — — (3 ) (in millions) December 31, 2015 Derivative Assets Energy Derivative Contracts $ 2 $ 1 $ — $ 1 Derivative Liabilities Energy Derivative Contracts (13 ) (1 ) — (12 ) Interest Rate Swap (3 ) — — (3 )
Financial Impact of Energy Contracts	Energy Derivative Contracts - Regulatory Recovery We record unrealized gains and losses on energy purchase contracts that are recoverable through the PPFAC in the balance sheet as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statement or in the statement of other comprehensive income, as shown in following table: Three Months Ended March 31, (in millions) 2016 2015 Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities $ (2 ) $ (6 )
Derivative Volumes	Derivative Volumes At March 31, 2016 , we have energy contracts that will settle through 2019 . The volumes associated with our energy contracts were as follows: March 31, 2016 December 31, 2015 Power Contracts GWh 1,282 1,752 Gas Contracts GBtu 15,165 17,214
Level 3 Fair Value Quantitative Information Regarding Unobservable Inputs	The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements: Valuation Fair Value of Range of Approach Assets Liabilities Unobservable Inputs Unobservable Input (in millions) March 31, 2016 Forward Power Contracts Market approach $ 1 $ (3 ) Market price per MWh $ 15.90 $ 29.90 Gas Option Contracts Option model — (1 ) Market price per MMBtu $ 1.50 $ 2.67 Gas volatility 34.3 % 46.0 % Level 3 Energy Contracts $ 1 $ (4 ) Valuation Fair Value of Range of Approach Assets Liabilities Unobservable Inputs Unobservable Input (in millions) December 31, 2015 Forward Power Contracts Market approach $ 1 $ (2 ) Market price per MWh $ 19.20 $ 31.35 Gas Option Contracts Option model — (1 ) Market price per MMBtu $ 2.17 $ 2.69 Gas volatility 31.0 % 58.3 % Level 3 Energy Contracts $ 1 $ (3 )
Level 3 Fair Value Reconciliation of Changes	The following table presents a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy: Three Months Ended March 31, (in millions) 2016 2015 Beginning of Period $ (2 ) $ (9 ) Gains (Losses) Recorded to: (1) Regulatory Assets or Liabilities – Derivative Instruments (1 ) (2 ) Settlements — (1 ) End of Period $ (3 ) $ (12 ) (1) Includes gains (losses) attributable to the change in unrealized gains/(losses) relating to assets (liabilities) still held at the end of the period of $(1) million and $(3) million , for the three months ended March 31, 2016 and 2015 , respectively.
Face Value and Estimated Fair Value of Long-Term Debt	The following table includes the face value and estimated fair value of our long-term debt: Fair Value Hierarchy Face Value Fair Value (in millions) March 31, 2016 December 31, 2015 March 31, 2016 December 31, 2015 Liabilities Long-Term Debt, including Current Maturities Level 2 $ 1,466 $ 1,466 $ 1,526 $ 1,529

NATURE OF OPERATIONS AND FINA25

NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION (Nature of Operations) (Details) customer in Thousands	3 Months Ended
	Mar. 31, 2016mi²customer
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Retail Electric Customers [customer count] | customer	418
Area In Which Company Generates Transmits And Distributes Electricity To Retail Electric Customers [square mile] | mi²	1,155

REGULATORY MATTERS (Rate Case)

REGULATORY MATTERS (Rate Case) (Details) - Arizona Corporation Commission [Member] $ in Millions	1 Months Ended
	Nov. 30, 2015USD ($)
Public Utilities, General Disclosures [Line Items]
Requested Base Rate Increase Amount	$ 110
Requested Base Rate Increase, Percentage	12.00%
Requested Return on Original Cost Rate Base, Percentage	7.34%
Original Cost Rate Base	$ 2,100

REGULATORY MATTERS (Cost Recove

REGULATORY MATTERS (Cost Recovery Mechanisms) (Details) $ in Millions	1 Months Ended		3 Months Ended
	Apr. 30, 2016$ / kWh	Feb. 29, 2016USD ($)	Mar. 31, 2016USD ($)$ / kWh	Mar. 31, 2015USD ($)
Purchased Power and Fuel Adjustment Clause [Member] | Effective April 2015 Through April 2016 [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [dollars per kwh] | $ / kWh			0.0068
Purchased Power and Fuel Adjustment Clause [Member] | Effective October 2014 through March 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [dollars per kwh] | $ / kWh			0.0050
Demand Side Management - Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Recovery Revenue | $			$ 2	$ 3
Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Approved Recovery of Energy Efficiency Plan | $		$ 14
Lost Fixed Cost Recovery Mechanism - Energy Efficiency Standards [Member]
Public Utilities, General Disclosures [Line Items]
Recovery Revenue | $			$ 5	$ 3
Cap on Increase in Lost Fixed Cost Recovery Rate			1.00%
Subsequent Event [Member] | Purchased Power and Fuel Adjustment Clause [Member] | Effective May 2016 Through March 2017 [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Power And Fuel Adjustment Clause Rate [dollars per kwh] | $ / kWh	0.0015

REGULATORY MATTERS (FERC Matter

REGULATORY MATTERS (FERC Matters) (Details) $ in Millions	Apr. 21, 2016USD ($)
FERC refund order [Member] | Subsequent Event [Member]
Public Utilities, General Disclosures [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 13

REGULATORY MATTERS REGULATORY M

REGULATORY MATTERS REGULATORY MATTERS (Regulatory Assets) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Regulatory Assets	$ 277,000	$ 264,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1 year
Regulatory Assets, Current	$ 62,406	51,841
Regulatory Assets, Noncurrent	214,717	212,312
Pension and Other Postretirement Benefits [Member]
Regulatory Assets [Line Items]
Regulatory Assets	118,000	120,000
Final Mine Reclamation and Retiree Health Care Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 29,000	28,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	21 years
Property Tax Deferrals [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 22,000	21,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1 year
Springerville Unit 1 Leasehold Improvements - Third Party Owners [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 20,000	21,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	7 years
Public Utilities, Property, Plant and Equipment, Generation, Useful Life	10 years
Income Taxes Recoverable through Future Rates [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 19,000	26,000
Lost Fixed Cost Recovery Mechanism [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 19,000	16,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1 year
Sundt Coal Handling Facilities [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 17,000	0
Derivatives [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 14,000	12,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	3 years
Other Regulatory Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 19,000	$ 20,000

REGULATORY MATTERS (Regulatory

REGULATORY MATTERS (Regulatory Liabilities) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 362,000	$ 360,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1 year
Regulatory Liability, Current	$ 59,862	53,077
Regulatory Liability, Noncurrent	302,367	307,286
Net Cost of Removal for Interim Retirements [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	261,000	264,000
Deferred Investment Tax Credit [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	32,000	32,000
Renewable Energy Standards (RES) [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	25,000	25,000
Purchased Power and Fuel Adjustment Clause [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 25,000	18,000
Remaining Recovery Period of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1 year
Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 19,000	$ 21,000

RELATED PARTY TRANSACTIONS (Rec

RELATED PARTY TRANSACTIONS (Receivables From/To and Goods and Services Provided By/To) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts Receivable—Due from Affiliates	$ 4		$ 7
Accounts Payable—Due to Affiliates	3		6
Transmission Sales To UNS Electric [Member]
Related Party Transaction [Line Items]
Sales to Affiliates	1	$ 1
Wholesale Sales to UNS Electric [Member]
Related Party Transaction [Line Items]
Sales to Affiliates	0	1
Common Costs Provided to UNS Energy Affiliates [Member]
Related Party Transaction [Line Items]
Common Costs	3	3
Supplemental Workforce provided to TEP [Member]
Related Party Transaction [Line Items]
Supplemental Workforce	4	4
Corporate Services - UNS Energy to TEP [Member]
Related Party Transaction [Line Items]
Corporate Services	2	1
UNS Electric [Member]
Related Party Transaction [Line Items]
Accounts Receivable—Due from Affiliates	3		6
Accounts Payable—Due to Affiliates	0		2
UNS Gas [Member]
Related Party Transaction [Line Items]
Accounts Receivable—Due from Affiliates	1		1
SES [Member]
Related Party Transaction [Line Items]
Accounts Payable—Due to Affiliates	2		2
UNS Energy [Member]
Related Party Transaction [Line Items]
Accounts Payable—Due to Affiliates	$ 1		$ 2
Intercompany Allocation Parent to Subsidiary	82.00%
Fortis [Member]
Related Party Transaction [Line Items]
Management fee	$ 2	$ 1

RELATED PARTY TRANSACTIONS (Div

RELATED PARTY TRANSACTIONS (Dividend Paid) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Related Party Transactions [Abstract]
Dividends, Common Stock	$ 0	$ 0
Cash Dividends Paid to Parent Company	$ 0	$ 0

DEBT, CREDIT FACILITIES, AND 33

DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS (Capital Leases) (Details) - Springerville Coal Handling Facilities [Member] - Tri-State [Member] - USD ($) $ in Millions	Mar. 31, 2016	Apr. 30, 2015
Capital Lease Asset Purchase Commitment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		17.05%
Asset Purchase Option Amount		$ 24
Utility Plant, Proportionate Ownership Share Held for Sale	17.05%

COMMITMENTS AND CONTINGENCIES34

COMMITMENTS AND CONTINGENCIES (COMMITMENTS) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)facility
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	$ 24
2,017	26
2,018	27
2,019	27
2,020	26
Thereafter	65
Total	195
Fuel, Including Transportation
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	21
2,017	23
2,018	24
2,019	24
2,020	23
Thereafter	22
Total	137
Renewable Power Purchase Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2,016	3
2,017	3
2,018	3
2,019	3
2,020	3
Thereafter	43
Total	$ 58
Percentage of certain renewable energy generation facilities output required to be purchased by TEP once commercial operation status achieved	100.00%
Number of facilities which acheived commercial operation status in the first three months of 2016 | facility	1

COMMITMENTS AND CONTINGENCIES35

COMMITMENTS AND CONTINGENCIES (CONTINGENCIES) (Detail) - USD ($)	1 Months Ended		3 Months Ended
	Mar. 31, 2016	Feb. 29, 2016	Mar. 31, 2016	May. 02, 2016	Apr. 21, 2016	Dec. 31, 2015
Commitments And Contingencies [Line Items]
Share of Defaulting Participants' Payment on Performance Guarantees	$ 0		$ 0
FERC refund order [Member]
Commitments And Contingencies [Line Items]
Payables to Customers	13,000,000		13,000,000
FERC refund order [Member] | Subsequent Event [Member]
Commitments And Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss					$ 13,000,000
Springerville Unit One [Member] | Springerville Unit 1 Third Party Owner Allegation [Member] | Pending Settlement [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station		50.50%
Purchase Obligation for Third-Party Owner's undivided interest in Springerville Unit 1		$ 85,000,000
Settlement Amount		$ 12,500,000
Loss Contingency, Damages Sought, Value			71,000,000
Accounts Receivable—Other	29,000,000		29,000,000
Receivable for Capital	$ 6,000,000		$ 6,000,000
Springerville Unit One [Member] | Springerville Unit 1 Third Party Owner Allegation [Member] | Pending Settlement [Member] | Subsequent Event [Member]
Commitments And Contingencies [Line Items]
Amount paid by Spr Unit 1 Third Party Owners				$ 0
San Juan [Member] | Surface Mine Possible Additional Royalty Assessment, Coal Supplier [Member]
Commitments And Contingencies [Line Items]
Percentage of ownership in generating station	50.00%		50.00%
Loss Contingency, Damages Sought, Value			$ 5,000,000
Loss Contingency, Estimate of Possible Loss	$ 1,000,000		$ 1,000,000
Approximate percentage of the generation capacity of the station	20.00%		20.00%
Four Corner [Member] | Coal Severance Tax, Penalties, and Interest Assessed to Coal Supplier [Member]
Commitments And Contingencies [Line Items]
Settlement Amount	$ 1,000,000
Four Corner [Member] | Coal Severance Tax, Penalties, and Interest Assessed to Coal Supplier [Member] | Pending Litigation [Member]
Commitments And Contingencies [Line Items]
Loss Contingency, Damages Sought, Value			$ 30,000,000
Loss Contingency, Estimate of Possible Loss	$ 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, Estimate of Possible Loss	$ 4,000,000		$ 4,000,000			$ 3,000,000
Loss Contingency Accrual, Provision			1,000,000
Navajo, San Juan, Four Corners [Member]
Commitments And Contingencies [Line Items]
TEP's share of reclamation costs at expiration dates of the coal supply agreements			42,000,000
Reclamation liability reflected in balance sheets	$ 25,000,000		$ 25,000,000			$ 25,000,000

EMPLOYEE BENEFIT PLANS (Compone

EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Pension Benefits [Member]
Components of Net Periodic Benefit Plan Cost
Service Cost	$ 3	$ 3
Interest Cost	4	4
Expected Return on Plan Assets	(6)	(6)
Amortization of Net Loss/(Gain)	2	2
Net Periodic Benefit Cost	3	3
Other Postretirement Benefits [Member]
Components of Net Periodic Benefit Plan Cost
Service Cost	1	1
Interest Cost	0	1
Expected Return on Plan Assets	0	0
Amortization of Net Loss/(Gain)	0	0
Net Periodic Benefit Cost	$ 1	$ 2

SUPPLEMENTAL CASH FLOW INFORM37

SUPPLEMENTAL CASH FLOW INFORMATION (Non-Cash Transactions) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Other Noncash Investing and Financing Items [Abstract]
Accrued Capital Expenditures	$ 14	$ 30
Net Cost Of Removal Of Interim Retirements	$ 3	$ 6

FAIR VALUE MEASUREMENTS AND D38

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Measured at Fair Value on a Recurring Basis) (Detail) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Assets
Cash Equivalents	$ 44	$ 33
Restricted Cash	4	4
Derivative Derivative Contract Assets - Regulatory Recovery		1
Energy Derivative Contract Assets - No Regulatory Recovery	1	1
Total Assets	49	39
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(14)	(13)
Interest Rate Swap	(3)	(3)
Total Liabilities	(17)	(16)
Net Total Assets (Liability)	32	23
Level 1 [Member]
Assets
Cash Equivalents	44	33
Restricted Cash	4	4
Derivative Derivative Contract Assets - Regulatory Recovery		0
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	48	37
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	0	0
Interest Rate Swap	0	0
Total Liabilities	0	0
Net Total Assets (Liability)	48	37
Level 2 [Member]
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Derivative Derivative Contract Assets - Regulatory Recovery		1
Energy Derivative Contract Assets - No Regulatory Recovery	0	0
Total Assets	0	1
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(10)	(10)
Interest Rate Swap	(3)	(3)
Total Liabilities	(13)	(13)
Net Total Assets (Liability)	(13)	(12)
Level 3 [Member]
Assets
Cash Equivalents	0	0
Restricted Cash	0	0
Derivative Derivative Contract Assets - Regulatory Recovery		0
Energy Derivative Contract Assets - No Regulatory Recovery	1	1
Total Assets	1	1
Liabilities
Energy Derivative Contract Liabilities - Regulatory Recovery	(4)	(3)
Interest Rate Swap	0	0
Total Liabilities	(4)	(3)
Net Total Assets (Liability)	$ (3)	$ (2)

FAIR VALUE MEASUREMENTS AND D39

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Potential Offset of Counterparty Netting and Cash Collateral) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Energy Related Derivative [Member]
Gross, Net, and Offsetting Amounts [Line Items]
Derivative Asset, Fair Value, Gross Amount Recognized on the Balance Sheets	$ 1	$ 2
Derivative Asset, Counterparty Netting	0	1
Collateral Received	0	0
Derivative Asset, Net Amount	1	1
Derivative Liability, Fair Value, Gross Amount Recognized on the Balance Sheets	(14)	(13)
Derivative Liability, Counterparty Netting	0	(1)
Collateral Posted	0	0
Derivative (Liability), Net Amount	(14)	(12)
Interest Rate Swap [Member]
Gross, Net, and Offsetting Amounts [Line Items]
Derivative Liability, Fair Value, Gross Amount Recognized on the Balance Sheets	(3)	(3)
Derivative Liability, Counterparty Netting	0	0
Collateral Posted	0	0
Derivative (Liability), Net Amount	$ (3)	$ (3)

FAIR VALUE MEASUREMENTS AND D40

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedges) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)
Derivative [Line Items]
Cash Flow Hedge Loss to be Reclassified within Twelve Months	$ 1
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative Liability, Notional Amount	$ 23

FAIR VALUE MEASUREMENTS AND D41

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Cash Flow Hedge - Realized Losses) (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Realized losses from cash flow hedges less than	$ 1,000,000	$ 1,000,000

FAIR VALUE MEASUREMENTS AND D42

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Impact of Derivative Energy Contracts) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Percent of gains shared with ratepayers	10.00%
Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities	$ (2)	$ (6)

FAIR VALUE MEASUREMENTS AND D43

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Derivative Volumes) (Details)	Mar. 31, 2016GWhBTU	Dec. 31, 2015GWhBTU
Power Contracts (in GWh) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes | GWh	1,282	1,752
Gas Contracts (in Btu) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives Volumes | BTU	15,165,000,000	17,214,000,000

FAIR VALUE MEASUREMENTS AND D44

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Level 3 Fair Value Measurements) (Detail) - Level 3 [Member] $ in Millions	Mar. 31, 2016USD ($)$ / MMBTU$ / megawatt_hour	Dec. 31, 2015USD ($)$ / MMBTU$ / megawatt_hour
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	$ 1	$ 1
Derivative Liabilities	(4)	(3)
Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	1	1
Derivative Liabilities	(3)	(2)
Valuation Technique Option Model [Member] | Gas Option Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Derivative Assets	0	0
Derivative Liabilities	$ (1)	$ (1)
Minimum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price | $ / megawatt_hour	15.90	19.20
Minimum [Member] | Valuation Technique Option Model [Member] | Gas Option Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price | $ / MMBTU	1.50	2.17
Gas volatility	34.30%	31.00%
Maximum [Member] | Market Approach Valuation Technique [Member] | Forward Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price | $ / megawatt_hour	29.90	31.35
Maximum [Member] | Valuation Technique Option Model [Member] | Gas Option Contracts [Member]
Fair Value Inputs Assets Liabilities Quantitative Information [Line Items]
Market price | $ / MMBTU	2.67	2.69
Gas volatility	46.00%	58.30%

FAIR VALUE MEASUREMENTS AND D45

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Reconciliation of Changes in Fair Value of Assets and Liabilities) (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning balance	$ (2,000,000)	$ (9,000,000)
Gains/(Losses) Recorded to:
Gains/(Losses) Recorded to Net Regulatory Assets/Liabilities - Derivative Instruments	(1,000,000)	(2,000,000)
Settlements	0	(1,000,000)
Ending balance	(3,000,000)	(12,000,000)
Change in Unrealized Gains (Losses) relating to Assets (Liabilities) still held	(1,000,000)	(3,000,000)
Transfers out of Level 3	$ 0	$ 0

FAIR VALUE MEASUREMENTS AND D46

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Credit Risk) (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
FV of derivative instruments in net liability position with credit risk related features	$ 23,000,000	$ 20,000,000
Additional collateral if credit-risk contingent features are triggered	23,000,000
Accounts Payable and Accrued Liabilities [Member]
Derivative [Line Items]
Additional collateral if credit-risk contingent features are triggered	8,000,000
Line of Credit Collateral [Member]
Derivative [Line Items]
LOCs	$ 0

FAIR VALUE MEASUREMENTS AND D47

FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS (Financial Instruments Not Carried at Fair Value) (Detail) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Including Current Maturities, Face Value	$ 1,466	$ 1,466
Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-Term Debt, including Current Maturities, Fair Value	$ 1,526	$ 1,529