~~RESTRICTED CASH~~

~~Cash balances that~~INVENTORY

TEP values materials, supplies, and fuel inventory at the lower of weighted average cost and net realizable value. Materials and supplies consist of generation, transmission, and distribution construction and repair materials. The majority of TEP's inventory will be recovered in rates charged to ratepayers. Handling and procurement costs (such as labor, overhead costs, and transportation costs) are ~~restricted regarding withdrawal or usage based on contractual or regulatory considerations are reported in Investments and Other Property—Other on~~capitalized as part of the ~~balance sheets. Restricted cash was $2 million at December 31, 2014 and December 31, 2013.~~cost of the inventory.

UTILITY PLANT

Utility ~~Plant~~plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. ~~We report utility~~Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction (AFUDC), less contributions in aid of construction.

~~We record the~~The cost of repairs and maintenance, including planned ~~major~~generation overhauls, are expensed to Operations and Maintenance ~~(O&M) expense in~~Expense on the ~~income statement~~Consolidated Statements of Income as costs are incurred.

When TEP retires a unit of regulated property, ~~is retired, we reduce~~ accumulated depreciation is reduced by the original cost plus removal costs less any salvage value. There is no impact to the income ~~statement impact.~~statement.

AFUDC and Capitalized Interest

AFUDC reflects the cost of debt and equity funds used to finance construction and is capitalized as part of the cost of regulated utility plant. AFUDC amounts are capitalized and amortized through depreciation expense as a recoverable cost in Retail Rates. ~~For operations that do not apply regulatory accounting, we capitalize interest related only to debt as a cost of construction.~~ The capitalized interest that relates to debt is recorded as a reduction in Interest Expense inon the ~~income statement.~~Consolidated Statements of Income. The capitalized cost for equity funds is recorded asin Other Income inon the ~~income statement.~~Consolidated Statements of Income.

The average AFUDC rates on regulated construction expenditures are included in the table below:

2014 2013 2012
Average AFUDC Rates 7.30 % 7.38 % 7.22 %



	2017		2016		2015
Average AFUDC Rates	7.31	%	7.47	%	6.12	%

Depreciation

~~We compute depreciation~~Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. See Note ~~2 and Note~~ 3 ~~of Notes to Consolidated Financial Statements.~~for additional information regarding utility plant. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the ~~Federal Energy Regulatory Commission (FERC).~~FERC. Depreciation rates are based on average useful lives and include estimates for salvage value and removal costs.

Below are the summarized average annual depreciation rates for all utility plant:

2014 2013 2012
Average Annual Depreciation Rates 2.99 % 3.16 % 3.22 %



	2017		2016		2015
Average Annual Depreciation Rates	2.97	%	2.85	%	2.83	%

Utility Plant Under Capital Leases

TEP ~~financed~~finances a portion of the ~~following generation assets~~Springerville Common Facilities with capital leases: Springerville Unit 1; facilities at Springerville used in common with Springerville Unit 1 and Unit 2 (Springerville Common Facilities); and the Springerville Coal Handling Facilities. The capitalleases. Capital lease expense ~~incurred consists of~~is recorded in Amortization Expense ~~(see~~and in Interest Expense—Capital Leases on the Consolidated Statements of Income. See Note 3 ~~of Notes~~for additional information regarding utility plant and Note 6 for additional information related to ~~Consolidated Financial Statements) and Interest Expense—Capital Leases. The~~the lease ~~terms are described in Note 5 of Notes to Consolidated Financial Statements.~~terms.

Computer Software Costs

~~We capitalize costs~~Costs incurred to purchase and develop internal use computer software are capitalized and ~~amortize those costs~~amortized over the estimated economic life of the product. If the software is no longer useful ~~we immediately charge capitalized computer software costs to expense.~~

~~INVESTMENTS IN LEASE EQUITY~~

Prior to December 2014, TEP held a 14.1% equity interest in Springerville Unit 1 and a 7% interest in certain Springerville Common Facilities (Springerville Unit 1 Leases). The fair value of these investments is described in Note 10 of Notes to Consolidated Financial Statements.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

TEP accounted for its equity interest in the Springerville Unit 1 Lease trust using the equity method. In December 2014, following the purchase of an additional undivided interest in Springerville Unit 1, TEP transferred the balance of its investment in lease equity to Plant in Service.

~~ASSET RETIREMENT OBLIGATIONS~~

TEP has identified legal Asset Retirement Obligations (AROs) related to the retirement of certain generation assets. Additionally, TEP incurred AROs related to its photovoltaic assets as a result of entering into various ground leases. We record a liability for a legal ARO in the period in which it is incurred if it can be reasonably estimated. When a new obligation is recorded, we capitalize the cost of the liability by increasingor impaired, the carrying ~~amount of~~value is reduced and recorded as an expense on the related long-lived asset. We record the increase in the liability due to the passage of time by recognizing accretion expense in O&M expense and depreciate the capitalized cost over the useful life of the related asset or when applicable, the terms of the lease subject to ARO requirements. Beginning July 1, 2013, TEP began deferring costs associated with the majority of its legal AROs as regulatory assets because new depreciation rates approved in the 2013 TEP Rate Order include these costs.

Depreciation rates also include a component for estimated future removal costs that have not been identified as legal obligations. We recover those amounts in the rates charged to retail customers and have recorded an obligation for estimated costs of removal as regulatory liabilities.income statement.

EVALUATION OF ASSETS FOR IMPAIRMENT

~~We evaluate long-lived~~Long-lived assets and investments are evaluated for impairment whenever events or circumstances indicate the carrying value of the assets may be impaired. If expected future cash flows (without discounting) are less than the carrying value of the asset, an impairment loss is recognized if the impairment is other-than-temporary and the loss is not recoverable through rates.

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DEFERRED FINANCING COSTS

~~We defer~~Using the effective interest method, costs to issue debt are deferred and ~~amortize such costs~~amortized to interest expense on a straight-line basis over the life of the debt. Deferred debt issuance costs are presented in the balance sheet as ~~this approximates~~a direct deduction from the ~~effective interest method.~~carrying value of the associated debt liability. These costs include underwriters’ commissions, discounts or premiums, and other costs such as legal, accounting, regulatory fees, and printing costs.

~~We defer and amortize the~~TEP accounts for debt issuance costs related to credit facility arrangements as an asset.

The gains and losses on reacquired debt associated with regulated operations are deferred and amortized to interest expense over the remaining life of the original debt.

OPERATING REVENUES

~~We recognize revenues~~Revenues related to the sale of energy are recognized when services or commodities are delivered to customers. The billing for the delivery of ~~electricity sales~~power to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Operating revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end of the month, amounts of energy delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using average customer Retail Rates.

Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events, if certain criteria are met. TEP charges customers the ACC-authorized tariff price plus separate ACC-authorized surcharges. TEP has identified its LFCR mechanism and DSM performance incentive as alternative revenues. The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. The LFCR surcharge is assessed as a percentage of the customer’s bill. Revenue recognition related to the LFCR mechanism creates a regulatory asset until such time as the revenue is collected. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of TEP's applicable retail revenues, as approved in the 2017 Rate Order. In addition, the ACC approves a new DSM surcharge annually, which is effective June 1 of each year, to compensate TEP for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs are reflected in TEP’s non-fuel base rates as well as a performance incentive. TEP collects the DSM surcharge on a per kWh basis for residential customers and on a percentage of bill basis for non-residential customers. See Note 2 for additional information regarding regulatory matters.

For purchased power and wholesale sales contracts that are settled financially, TEP nets the ~~sales~~purchased power contracts with the ~~purchase power~~sales contracts and reflects the ~~net~~ amount ~~as Electric~~in Wholesale ~~Sales.~~Revenues on the Consolidated Statements of Income.

TEP recognizes monthly management fees in Other Revenues on the Consolidated Statements of Income as the operator of Springerville Unit 3 on behalf of Tri-State ~~Generation and Transmission Association, Inc. (Tri-State)~~ and Springerville Unit 4 on behalf of ~~Salt River Project Agriculture Improvement and Power District (SRP).~~SRP. Additionally, Other Revenues ~~include~~includes reimbursements from Tri-State and SRP for various operating expenses at Springerville and for the use of the Springerville Common Facilities and ~~the~~ Springerville Coal Handling Facilities. The offsetting expenses are recorded in ~~the~~their respective line items ofon the income ~~statements~~statement based on the nature of services provided. As the operating agent for Tri-State, ~~and SRP,~~ TEP may earn performance incentives based on unit availability which are recognized in Other Revenues on the Consolidated Statements of Income in the period earned.

The ACC has authorized mechanisms for Lost Fixed Cost Recovery (LFCR) related to kWh sales lost due to Energy Efficiency (EE) Standards and Distributed Generation (DG). We recognize revenues in the period that verifiable energy savings occur. Revenue recognition related to the LFCR creates a regulatory asset until such time as the revenue is collected.

~~ALLOWANCE FOR DOUBTFUL ACCOUNTS~~

We record an Allowance for Doubtful Accounts to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is determined based on historical bad debt patterns, retail sales, and economic conditions.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~INVENTORY~~

We value materials, supplies and fuel inventory at the lower of weighted average cost or market, unless evidence indicates that the weighted average cost (even if in excess of market) will be recovered in retail rates. We capitalize handling and procurement costs (such as labor, overhead costs, and transportation costs) as part of the cost of the inventory. Materials and Supplies consist of generation, transmission, and distribution construction and repair materials.

PURCHASED POWER AND FUEL ADJUSTMENT CLAUSE

~~We recover~~TEP recovers the actual fuel, purchased power, and transmission costs to provide electric service to retail customers through base fuel rates and through a ~~Purchased Power and Fuel Adjustment Clause (PPFAC); the~~PPFAC mechanism. The ACC periodically adjusts the PPFAC rate at which TEP recovers these costs. The difference between costs recovered through rates and actual fuel, purchased power, transmission, and other approved costs to provide retail electric service is deferred. Cost over-recoveries are deferred as regulatory liabilities and cost under-recoveries are deferred as regulatory assets. See Note 2 ~~of Notes to Consolidated Financial Statements.~~for additional information regarding regulatory matters.

RENEWABLE ENERGY AND ENERGY EFFICIENCY PROGRAMS

The ACC’s ~~Renewable Energy Standard (RES)~~RES requires ~~TEP~~Arizona regulated utilities to increase ~~its~~their use of renewable energy each year until it represents at least 15% of ~~its~~their total annual retail energy requirements inby 2025, with ~~distributed generation~~DG accounting for 30% of the annual renewable energy requirement. ~~TEP~~Arizona utilities must file an annual RES implementation plan for review and approval by the ACC. The approved ~~cost~~costs of carrying out this plan isare recovered from retail customers through the RES surcharge. The ~~ACC has also approved recovery of operating costs, depreciation, property taxes, and a return on investments in company-owned solar projects~~associated lost revenues attributable to meeting DG targets will be partially recovered through the ~~RES tariff until such costs are reflected in retail customer rates.~~LFCR mechanism.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEP is required to implement cost-effective ~~Demand Side Management (DSM)~~DSM programs to comply with the ACC’s EE Standards. The EE Standards provide ~~for~~regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs. The ~~Electric~~ EE Standards require increasing annual targeted retail ~~Kilowatt-hours (kWh)~~kWh savings equal to 22% by 2020.

Any RES or DSM ~~surcharge collections~~surcharges collected above or below the costs incurred to implement the plans are deferred and reflected in the ~~financial statements~~balance sheet as a regulatory ~~asset~~liability or ~~liability.~~asset. TEP recognizes RES and DSM surcharge revenue in ~~Electric~~ Retail ~~Sales~~Revenues on the Consolidated Statements of Income in amounts necessary to offset recognized qualifying expenditures.

RENEWABLE ENERGY CREDITS

The ACC measures compliance with the RES requirements through ~~Renewable Energy Credits (RECs).~~RECs. A REC represents one kWh generated from renewable resources. When TEP purchases renewable energy, the premium paid above the market cost of conventional power equals the REC cost recoverable through the RES surcharge. As described above, the market cost of conventional power is recoverable through the ~~PPFAC.~~PPFAC mechanism.

When RECs are purchased, TEP records the cost of the RECs (an indefinite-lived intangible asset) as ~~Other Assets,~~other assets and a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, TEP recognizes ~~Purchased Power~~purchased power expense and ~~Other Revenues~~other revenues in an equal amount. TEP had $42 million and $24 million of RECs as of December 31, 2017 and 2016, respectively. RECs are included in Regulatory and Other Assets—Other on the Consolidated Balance Sheets. See Note 2 ~~of Notes~~for additional information regarding regulatory matters.

TAXES OTHER THAN INCOME TAXES

TEP acts as a conduit or collection agent for sales taxes, utility taxes, franchise fees, and regulatory assessments. Trade receivables are recorded as the Company bills customers for these taxes and assessments. Simultaneously, liabilities payable to ~~Consolidated Financial Statements.~~governmental agencies are recorded in the balance sheet for these taxes and assessments. These amounts are not reflected in the income statement.

INCOME TAXES

Due to the difference between GAAP and income tax laws, many transactions are treated differently for income tax purposes than for financial statement presentation purposes. Temporary differences are accounted for by recording deferred income tax assets and liabilities on ~~our~~the balance ~~sheets.~~sheet. These assets and liabilities are recorded using enacted income tax rates expected to be in effect when the deferred tax assets and liabilities are realized or settled. ~~We reduce~~TEP reduces deferred tax assets by a valuation allowance when, in the opinion of management, it is more likely than not ~~that~~ some portion, or the entire deferred income tax asset, will not be realized.

Tax benefits are recognized when it is more likely than not that a tax position will be sustained upon examination by the tax authorities based on the technical merits of the position. The tax benefit recorded is the largest amount that is more than 50% likely to be realized upon ultimate settlement with the tax authority, assuming full knowledge of the position and all relevant facts. Interest expense accruals relating to income tax obligations are recorded in Other Interest ~~Expense.~~Expense on the Consolidated Statements of Income.

~~Prior to 1990,~~ TEP flowed through to ratepayers certain accelerated tax benefits related to utility plant as the benefits were recognized on tax returns. Regulatory Assets – Noncurrent includes income taxes recoverable through future rates, which

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~reflects the future revenues due to TEP from ratepayers as these tax benefits reverse. See Note 2 of Notes to Consolidated Financial Statements.~~

~~We account~~accounts for federal energy credits generated prior to 2012 using the grant accounting model. The credit is treated as deferred revenue, which is recognized over the depreciable life of the underlying asset. The deferred tax benefit of the credit is treated as a reduction to income tax expense in the year the credit arises. Federal energy credits generated since 2012 are deferred as ~~Regulatory Liabilities – Noncurrent~~regulatory liabilities and amortized as a reduction in ~~Income Tax Expense~~income tax expense over the tax life of the underlying asset. Income ~~Tax Expense~~tax expense attributable to the reduction in tax basis is accounted for in the year the federal energy credit is generated and is deferred as a regulatory ~~assets effective July 1, 2013 due to the 2013 TEP Rate Order.~~asset. All other federal and state income tax credits are treated as a reduction to ~~Income Tax Expense~~income tax expense in the year the credit arises.

~~Income~~TEP records income tax liabilities ~~are allocated to TEP~~ based on ~~its~~TEP's taxable income as reported in the ~~FortisUS Inc.~~ consolidated tax ~~return.~~return of FortisUS.

~~TAXES~~PENSION AND OTHER ~~THAN INCOME TAXES~~POSTRETIREMENT BENEFITS

~~We act~~TEP sponsors noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits are based on years of service and average compensation. The Company also provides limited healthcare and life insurance benefits for retirees.

The Company recognizes the underfunded status of defined benefit pension plans as conduits or collection agents for sales taxes, utility taxes, franchise fees, and regulatory assessments. As we bill customers for these taxes and assessments, we record trade receivables. At the same time, we record liabilities payable to governmental agencies ona liability in the balance ~~sheet~~sheet. The underfunded status is measured as the difference between the fair value of the pension plans’ assets and the projected benefit

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

obligation for the pension plans. TEP recognizes a regulatory asset to the extent these ~~taxes~~future costs are probable of recovery in the rates charged to retail customers. The Company expects recovery of these costs over the estimated service lives of employees.

Additionally, TEP maintains a SERP for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.

Pension and ~~assessments. These amounts~~other postretirement benefit expenses are determined by actuarial valuations based on assumptions that the Company evaluates annually. See Note 8 for additional information regarding the employee benefit plans.

FAIR VALUE

As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange, and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not ~~reflected~~necessarily indicative of the amounts that could be realized in ~~the income statements.~~a current or future market exchange. See Note 11 for additional information regarding fair value.

DERIVATIVE INSTRUMENTS

~~We use~~The Company uses various physical and financial derivative instruments, including forward contracts, financial swaps, and call and put options, to meet forecasted load and reserve requirements, to reduce ~~our~~ exposure to energy commodity price volatility, and to hedge ~~our~~ interest rate risk exposure. ~~For all derivative~~Derivative instruments that do not meet the normal purchase or normal sale scope exception ~~we recognize derivative instruments~~will be recognized as either assets or liabilities on the ~~consolidated~~ balance ~~sheets~~sheet and ~~measure those instruments~~are measured at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation.

~~Cash Flow Hedges~~

~~TEP hedges the cash flow risk associated with unfavorable changes~~Commodity derivatives used in ~~the variable interest rates related to the leveraged lease arrangements~~normal business operations that are settled by physical delivery, among other criteria, are eligible for ~~the Springerville Common Lease~~ and ~~variable rate industrial development revenue~~may be designated as normal purchases or ~~pollution control revenue bonds (IDBs). In addition, TEP hedges the cash flow risk associated with a long-term wholesale power supply agreement that does~~normal sales. Normal purchases or normal sales contracts are not ~~qualify for regulatory recovery using a six-year power purchase swap agreement. TEP accounts for cash flow hedges as follows:~~

~~The effective portion of the change in the~~recorded at fair value ~~is recorded in AOCI~~ and settled amounts are recognized as cost of fuel, energy, and capacity on the ~~ineffective portion, if any, is recognized in earnings;~~income statement.

For derivatives designated as hedging contracts, TEP formally assesses, at inception and

~~When TEP determines a~~ thereafter, whether the hedging contract is no longer effective in offsetting the changes in cash flow of a hedged item, TEP recognizes the change in fair value in earnings. The unrealized gains and losses at that time remain in AOCI and are reclassified into earnings as the underlying hedged transaction occurs.

~~We formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives have been and are expected to remain~~ highly effective in offsetting changes in the ~~cash flows of~~ hedged ~~items.~~item. Also, TEP formally documents hedging activity by transaction type and risk management strategy.

~~Energy Contracts - Regulatory Recovery~~

~~TEP~~For derivatives not designated as hedging contracts, the settled amount is ~~authorized to recover~~generally included in regulated rates. Accordingly, the ~~costs of hedging activities entered into to mitigate energy price risk for retail customers. We record~~net unrealized gains and losses associated with interim price movements on ~~these energy derivatives as either a regulatory asset or regulatory liability to the extent they qualify for recovery through the PPFAC mechanism.~~

~~Energy Contracts - No Regulatory Recovery~~

~~From time to time, TEP may enter into forward~~ contracts ~~with long-term wholesale customers~~ that ~~qualify as derivatives. We record unrealized gains and losses on these energy derivatives in the income statement as they do not qualify for regulatory recovery.~~

~~Master Netting Agreements~~

We have elected gross presentation for our derivative contracts under master netting agreements and collateral positions. We separate all derivatives into current and long-term portions on the balance sheet.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~Normal Purchases and Normal Sales~~

We enter into forward energy purchase and sales contracts, including options, with counterparties that have generating capacity to support our current load forecasts or counterparties that have load serving requirements. We have elected the normal purchase or normal sales exception for these contracts which are not required to be measured at fair value and are accounted for ~~on an accrual basis.~~

~~Commodity Trading~~

~~We did not engage~~as derivatives and probable of inclusion in ~~trading of derivative financial instruments for the periods presented.~~

~~PENSION AND OTHER RETIREE BENEFITS~~

~~We sponsor noncontributory, defined benefit pension plans for substantially all employees and certain affiliate employees. Benefits~~regulated rates are ~~based on years of service and average compensation. We also provide limited health care and life insurance benefits for retirees.~~

~~We recognize the underfunded status of our defined benefit pension plans~~recorded as ~~a liability on our balance sheets. The underfunded status is measured as the difference between the fair value of the pension plans’~~regulatory assets and the projected benefit obligation for the pension plans. We recognize a regulatory asset to the extent these future costs are probable of recovery in the rates charged to retail customers and expect to recover these costs over the estimated service lives of employees.

~~Additionally, we maintain a Supplemental Executive Retirement Plan (SERP) for senior management. Changes in SERP benefit obligations are recognized as a component of AOCI.~~

~~Pension and other retiree benefit expenses are determined by actuarial valuations based on assumptions that we evaluate annually.~~liabilities. See Note ~~8 of Notes to Consolidated Financial Statements.~~11 for additional information regarding derivative instruments.

NOTE 2.REGULATORY MATTERS

The ACC and the FERC each regulate portions of ~~the~~ utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.

~~2013 TEP~~2017 RATE ORDER

~~The provisions~~In February 2017, the ACC issued a rate order for new rates that took effect February 27, 2017. Provisions of the ~~2013 TEP~~2017 Rate Order ~~which were effective July 1, 2013,~~ include, but are not limited to:

~~An annual~~a non-fuel base rate increase of $81.5 million, which includes $15 million of operating costs related to the 50.5% undivided interest in ~~Base Rates~~Springerville Unit 1 purchased by TEP in September 2016;

a 7.04% return on original cost rate base, which includes a cost of ~~approximately $76 million.~~equity component of 9.75% and a cost of debt component of 4.32%;

~~A revision~~

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adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and

approval of a request to apply excess depreciation ~~rates from an average~~reserves against the unrecovered NBV of San Juan Unit 2 and the coal handling facilities at Sundt due to early retirement.

The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2, which is currently expected to be completed in the first half of ~~3.32% to 3.0% for generation and distribution plant regulated by~~2018. TEP cannot predict the outcome of these proceedings.

FEDERAL TAX LEGISLATION - ACC DOCKET

In December 2017, the ACC ~~primarily due~~opened a docket requesting that all regulated utilities submit proposals to ~~revised estimates~~address passing the ongoing benefits of ~~asset removal costs, which has~~ the ~~effect~~TCJA through to customers. TEP will actively participate in this docket and work with the ACC to reach an equitable solution. The Company cannot predict the outcome of ~~reducing depreciation expense by approximately $11 million annually.~~

A LFCR mechanism that allows TEP to recover certain non-fuel costs that would otherwise go unrecovered due to reduced retail kWh sales attributed to EE programs and DG. The LFCR rate adjusts annually and is subject to ACC review and a year-over-year capthese proceedings or how they may impact results of ~~1% of TEP's total retail revenues.~~

~~An Environmental Compliance Adjustor (ECA) mechanism that allows TEP to recover~~operations in the ~~costs of complying with environmental standards required by federal~~current or other governmental agencies between rate cases. The ECA adjusts annually to recover environmental compliance costs and is subject to ACC approval and a cap of 0.025 cents per kWh, which approximates 0.25% of TEP's total retail revenues.future years. See Note 12 for additional information regarding the TCJA.

COST RECOVERY MECHANISMS

TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.

Purchased Power and Fuel Adjustment Clause

~~The~~TEP's PPFAC rate is adjusted annually each April 1st ~~(unless otherwise approved by the ACC)~~ and goes into effect for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: 1)(i) a forward component ~~under~~ which ~~TEP recovers or refunds differences~~is calculated by taking the difference between a) forecasted fuel ~~transmission,~~ and purchased power costs ~~for the upcoming calendar year and b) those embedded in the fuel rate~~ and the ~~current PPFAC rates;~~amount of those costs established in Retail Rates; and 2)(ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period. The PPFAC bank balance was over-collected by $9 million and $38 million as of December 31, 2017 and 2016, respectively.

In February 2017, the ACC approved a PPFAC credit to begin returning the over-collected PPFAC bank balance to customers. The table below presents TEP's PPFAC rates approved by the ACC:



Period	Cents per kWh
March 2017 through March 2018	(0.20	)
May 2016 through February 2017	0.15
April 2015 through April 2016	0.68
October 2014 through March 2015	0.50

Renewable Energy Standard

The ACC’s RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities must file an annual RES implementation plan for review and approval by the ACC.

In January 2018, the ACC approved TEP's 2018 RES implementation plan with a budget amount of $54 million. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded performance-based incentives for customer-installed DG; and (iii) various other program costs. TEP recognized $1 million of revenue in 2017 as a return on company-owned solar projects. TEP is no longer requesting recovery on company-owned solar projects through the RES mechanism and plans to request recovery of these types of costs through its rate case process. TEP suspended its rooftop solar program effective December 2016, but requested approval of a community solar program. The ACC is expected to consider this program in Phase 2 of TEP's rate case.

In 2017, the percentage of TEP's retail kWh sales attributable to the RES was approximately 10%, exceeding the overall 2017 RES requirement of 7%. Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain DG RECs, which ~~reconciles~~are used to demonstrate compliance with the DG requirement, the ACC approved a waiver of the 2017 and 2018 residential distributed renewable energy requirement.

Energy Efficiency Standards

61Under the EE Standards, the ACC requires electric utilities to implement cost-effective programs to reduce customers' energy consumption. The EE Standards require increasing cumulative annual targeted retail kWh savings equal to 22% by 2020. As of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

~~differences between actual fuel, transmission, and purchased power costs and those recovered through the combination of the fuel rate and the forward component for the preceding 12-month period.~~

In April 2014, the ACC approved a PPFAC rate for TEP of 0.10 cents per kWh for the period May through September 2014 and 0.50 cents per kWh for the period October 2014 through March 2015. TEP's PPFAC rate was 0.77 cents per kWh for the period of January 2013 through June 2013 and a credit of approximately 0.14 cents per kWh for the period July 2013 through April 2014.

~~San Juan Mine Fire Insurance Proceeds~~

In September 2011, a fire at the underground mine providing coal to San Juan Generating Station (San Juan) caused interruptions to mining operations and resulted in increased fuel costs. The 2013 TEP Rate Order required TEP to defer incremental fuel costs of $10 million from recovery under the PPFAC pending final resolution of an insurance claim by the San Juan Coal Company and distribution of insurance proceeds to San Juan participants. As of December 31, 2014, TEP has received insurance settlement proceeds of $8 million. The proceeds offset the deferred costs and are reflected in our cash flow statements as an other operating cash receipt. TEP expects to recover any remaining fuel costs, not reimbursed by insurance, through its PPFAC.

~~Environmental Compliance Adjustor~~

The 2013 TEP Rate Order provided for the ECA to recover costs associated with qualified investments to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP recognized ECA revenues of less than $1 million in 2014.

~~Renewable Energy Standards~~

~~TEP is required to expand its use of renewable~~2017, TEP’s cumulative annual energy ~~in order to meet the ACC’s Renewable Energy Standards (RES)~~savings were approximately 14%. TEP is authorized to recover costs associated with meeting the RES through a customer surcharge. These costs include purchases of RECs through Power Purchase Agreements (PPAs) and Performance Based Incentives (PBIs), as well as costs associated with utility-scale ownership of solar assets until the projects can be incorporated in Base Rates.

In December 2014, the ACC approved TEP's 2015 RES plan that included a spending budget of $40 million with $33 million to be recovered through the RES surcharge. TEP earned returns on solar investments of less than $1 million in 2014 and $2 million in 2013.

~~Energy Efficiency Standards~~

TEP is required to implement cost-effective DSM programs to comply with the ~~ACC's~~ACC’s EE Standards. The EE Standards provide ~~for~~regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as aan annual performance incentive. ~~For the year ended December 31, 2014,~~ TEP ~~recorded a~~records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million ~~that is~~in both 2017 and 2016, and $3 million in 2015 related to performance, included in ~~Electric~~ Retail ~~Revenue~~Revenues on the Consolidated Statements of Income.

In February 2016, the ACC approved TEP's 2016 energy efficiency implementation plan with a budget of approximately $22 million, which was partially offset by applying $8 million of previously recovered carryover funds. TEP has been approved to collect the remaining $14 million from retail customers through the DSM surcharge. Energy savings realized through the programs will count toward meeting the EE Standards and the associated lost revenue will be partially recovered through the LFCR mechanism.

In June 2016, TEP notified the ACC that it would not file a 2017 energy efficiency implementation plan and instead continue the 2016 level of recovery through the end of 2017. TEP reduced its costs and incentive levels for certain programs in order to minimize any potential under-collected DSM balance at the end of 2017.

In August 2017, TEP submitted its application for the 2018 energy efficiency implementation plan with a budget of $23 million and requested a waiver of the 2018 EE Standard. TEP expects to receive a decision on its 2018 energy efficiency implementation plan in the ~~TEP income statement.~~first half of 2018.

Lost Fixed Cost Recovery Mechanism

The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to ~~lost~~reduced retail kWh sales as a result of implementing ~~ACC approved EE~~ACC-approved energy efficiency programs and ~~DG targets. For recovery of lost fixed costs,~~customer-installed DG. TEP ~~is required to file an annual LFCR adjustment request with the ACC for costs related to the prior year,~~records a regulatory asset and ~~recovery is subject to a year-over-year cap of 1% of the company's total retail revenues.~~

The ACC approved TEP's annual LFCR recovery request for lost fixed costs incurred in 2013 of approximately $5 million. The approved rates, of approximately 0.41% of retail revenue for EE and approximately 0.31% of retail revenue for DG, became effective August 2014.

~~TEP recorded, in Electric Retail Sales,~~recognizes LFCR revenues ~~of $11 million for~~when the ~~year ended December 31, 2014 related to reductions in retail kWh sales for 2013 and 2014. We recognize LFCR revenue when~~amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to make an annual filing with the ACC requesting recovery of the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of TEP's applicable retail revenues, as approved in the 2017 Rate Order.

TEP recorded regulatory assets and recognized LFCR revenues of $22 million in 2017, $18 million in 2016, and $12 million in 2015. LFCR revenues are included in Retail Revenues on the Consolidated Statements of Income.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

REGULATORY ASSETS AND LIABILITIES

~~The following table summarizes regulatory~~Regulatory assets and ~~liabilities:~~liabilities recorded in the balance sheet are summarized in the table below:



	Remaining Recovery Period (years)	December 31,
($ in millions)	Remaining Recovery Period (years)	2017		2016
Regulatory Assets
Pension and Other Postretirement Benefits (Note 8)	Various	$	126	$	128
Early Generation Retirement Costs ⁽¹⁾	Various	84		—
Income Taxes Recoverable through Future Rates ⁽²⁾	Various	40		29
Final Mine Reclamation and Retiree Healthcare Costs ⁽³⁾	20	31		27
Lost Fixed Cost Recovery	1	29		23
Property Tax Deferrals ⁽⁴⁾	1	24		23
Springerville Unit 1 Leasehold Improvements ⁽⁵⁾	6	14		17
Sundt Coal Handling Facilities ⁽⁶⁾	N/A	—		14
Other Regulatory Assets	Various	40		20
Total Regulatory Assets		388		281
Less Current Portion	1	94		56
Total Non-Current Regulatory Assets		$	294	$	225



Regulatory Liabilities
Income Taxes Payable through Future Rates ⁽²⁾	Various	$	353	$	3
Net Cost of Removal ⁽⁷⁾	Various	180		270
Renewable Energy Standard	Various	44		32
Deferred Investment Tax Credits ⁽⁸⁾	Various	14		23
Purchased Power and Fuel Adjustment Clause	1	9		38
Other Regulatory Liabilities	Various	5		11
Total Regulatory Liabilities		605		377
Less Current Portion	1	89		76
Total Non-Current Regulatory Liabilities		$	516	$	301

⁽¹⁾

Includes the NBV and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Consolidated Balance Sheets due to the planned early retirement of the facilities. As of December 31, 2017, Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. See Note 3 for additional information related to the planned early retirement of Navajo and Sundt Units 1 and 2.


⁽²⁾	Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA. See Note 1 and Note 12 for additional information regarding income taxes.


⁽³⁾	Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to fully recover these costs through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2037.

⁽⁴⁾

Property taxes are recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months.


⁽⁵⁾	Represents investments TEP made, which were previously recorded in Plant in Service on the Consolidated Balance Sheets, to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year amortization period.

⁽⁶⁾

In June 2014, the EPA issued a final rule that required TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continued to use coal as a fuel source; or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. In March 2016, TEP notified the EPA of its decision to permanently eliminate coal as a fuel source, and transferred the NBV of the Sundt Coal Handling Facilities to a regulatory asset. TEP applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2014 December 31, 2013
Millions of Dollars
Regulatory Assets—Current
Property Tax Deferrals ⁽¹⁾
$ 21
$ 20
PPFAC ⁽²⁾
19
4
Derivative Instruments (Note 10) 15
1
LFCR and DSM ⁽²⁾
8
3
San Juan Mine Fire Cost Deferral ⁽²⁾
2
10
Other Current Regulatory Assets ⁽³⁾
4
5
Total Regulatory Assets—Current 69
43
Regulatory Assets—Noncurrent
Pension and Other Retiree Benefits (Note 8) 126
75
Income Taxes Recoverable Through Future Rates ⁽⁴⁾
31
22
PPFAC - Final Mine Reclamation and Retiree Health Care Costs ⁽⁵⁾
29
25
Springerville Lease Purchase Commitment Deferrals ⁽⁶⁾
16
2
Unamortized Loss on Reacquired Debt ⁽⁷⁾
6
7
LFCR ⁽²⁾
4
—
Tucson to Nogales Transmission Line ⁽⁸⁾
4
5
Other Regulatory Assets ⁽³⁾
7
5
Total Regulatory Assets—Noncurrent 223
141
Regulatory Liabilities—Current
RES ⁽²⁾
(28 ) (22 )
DSM ⁽²⁾
(6 ) —
Fortis Merger Customer Credits ⁽⁹⁾
(5 ) —
Other Current Regulatory Liabilities —
(2 )
Total Regulatory Liabilities—Current (39 ) (24 )
Regulatory Liabilities—Noncurrent
Net Cost of Removal for Interim Retirements ⁽¹⁰⁾
(265 ) (254 )
Deferred Investment Tax Credits ⁽¹¹⁾
(25 ) (4 )
Income Taxes Payable through Future Rates ⁽⁴⁾
(20 ) (5 )
Fortis Merger Customer Credits ⁽⁹⁾
(11 ) —
Total Regulatory Liabilities—Noncurrent (321 ) (263 )
Total Net Regulatory Assets (Liabilities) $ (68 ) $ (103 )

⁽⁷⁾

Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. As a result of the 2017 Rate Order, $87 million was transferred from Net Cost of Removal to Accumulated Depreciation and Amortization to reflect the impact of the revised depreciation study on the estimated cost of removal.


⁽⁸⁾	Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.

Regulatory assets are either being collected ~~in Retail Rates~~ or are expected to be collected through Retail ~~Rates in a future period.~~Rates. With the exception of ~~interest earned on under-recovered PPFAC costs, we do~~Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that weTEP either ~~expect~~expects to pay to customers through billing reductions in future periods or ~~plan~~plans to use for the purpose for which they were collected from customers.


⁽¹⁾	~~Property Taxes are recovered over approximately a six months period as costs are paid, rather than as costs are accrued.~~


⁽²⁾	~~See Cost Recovery Mechanisms discussed above.~~


⁽³⁾	Other regulatory assets include self-insured medical costs and short-term disability costs recovered on a pay-as-you-go or cash basis; San Juan Coal Contract Amendment costs (recovery through 2017); rate case costs (recovery over three years); and environmental compliance costs (recovery over one year).


⁽⁴⁾	~~Income Taxes Recoverable through Future Revenues are amortized over the life of the assets. See Note 1 of Notes to Consolidated Financial Statements.~~

With the exception of over-recovered PPFAC costs, TEP does not pay a return on regulatory liabilities.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~ FERC COMPLIANCE

In 2016, the FERC issued orders relating to certain late-filed TSAs, which resulted in TEP recording a liability and paying time-value refunds to the counterparties of these TSAs. In May 2017, the FERC informed TEP that the related investigation was closed. See Note 7 for additional information related to FERC compliance associated with these transmission contracts.

⁽⁵⁾

Final Mine Reclamation and Retiree Health Care Costs stem from TEP’s jointly-owned facilities at the San Juan Generating Station, the Four Corners Generating Station, and the Navajo Generating Station. TEP is required to recognize the present value of its liability associated with final mine reclamation and retiree health care obligations over the life of the coal supply agreements. TEP recorded a regulatory asset because TEP is permitted to fully recover these costs through the PPFAC when the costs are invoiced by the miners. TEP expects to recover these costs over the remaining life of the mines, which is estimated to be between 14 and 20 years.


⁽⁶⁾	TEP deferred the increase in lease interest expense relating to the purchase commitments for Springerville Unit 1 and the Springerville Coal Handling Facilities to a regulatory asset because TEP believes the full purchase price is recoverable in rate base. See Note 5 of Notes to Consolidated Financial Statements.


⁽⁷⁾	~~In accordance with FERC guidelines, when TEP refinances its long-term debt, TEP defers and amortizes losses on reacquired debt over the life of the debt agreement.~~


⁽⁸⁾	TEP will request recovery from FERC for the costs incurred to develop a high-voltage transmission line from Tucson to Nogales; the project is not going forward. See Note 6 of Notes to Consolidated Financial Statements


⁽⁹⁾	Fortis Merger Customer Credits represent credits to be applied to customers’ bills according to the Merger Agreement. These credits will be applied to customer bills each year, October through March for a period of five years. See Note 1 of Notes to Consolidated Financial Statements.


⁽¹⁰⁾	~~Net Cost of Removal for Interim Retirements represents amounts recovered through depreciation rates associated with asset retirement costs expected to be incurred in the future.~~


⁽¹¹⁾	~~The Deferred Investment Tax Credit relates to federal energy credits generated in 2012 and is amortized over the tax life of the underlying asset.~~

IMPACTS OF REGULATORY ACCOUNTING

If ~~we determine~~TEP determines that weit no longer ~~meet~~meets the criteria for continued application of regulatory accounting, weTEP would be required to write off ~~our~~its regulatory assets and liabilities related to those operations not meeting the regulatory accounting requirements. Discontinuation of regulatory accounting could have a material impact on ~~our~~TEP's financial statements.

NOTE 3.UTILITY PLANT AND JOINTLY-OWNED FACILITIES

UTILITY PLANT

The following table shows ~~Utility~~ Plant in Service on the Consolidated Balance Sheets by major class:

December 31,
2014 2013
Millions of Dollars
Plant in Service:
Electric Generation Plant $ 2,388
$ 1,889
Electric Transmission Plant 898
825
Electric Distribution Plant 1,398
1,298
General Plant 338
312
Intangible Plant - Software Costs ^{(1) (2)}
149
141
Electric Plant Held for Future Use 4
3
Total Plant in Service $ 5,175
$ 4,468

Utility Plant under Capital Leases⁽³⁾
$ 667
$ 638



	Annual Depreciation Rate ⁽⁴⁾	Average Remaining Life in Years ⁽⁴⁾	December 31,
($ in millions)	Annual Depreciation Rate ⁽⁴⁾	Average Remaining Life in Years ⁽⁴⁾	2017		2016
Plant in Service
Generation Plant	3.19%	25	$	2,548	$	2,866
Transmission Plant	1.48%	32	1,001		1,024
Distribution Plant	1.56%	36	1,632		1,512
General Plant	5.89%	12	389		381
Intangible Plant, Software Costs, and Other ⁽¹⁾	Various	Various	207		185
Plant Held for Future Use	—	—	4		7
Total Plant in Service ⁽²⁾			$	5,781	$	5,975

Utility Plant Under Capital Leases ⁽³⁾			$	85	$	167

⁽¹⁾

Primarily represents computer software. Unamortized computer software costs were ~~$31~~$59 million and $52 million as of December 31, ~~2014,~~2017 and ~~$39~~2016, respectively. The amortization of computer software costs was $19 million asin 2017, $17 million in 2016, and $14 million in 2015. Computer software is being amortized over its expected useful life ranging from three to five years for smaller application software and average remaining life of ~~December 31, 2013.~~three years for large enterprise software.


⁽²⁾	~~The amortization~~Includes plant acquisition adjustments of ~~computer software costs was $17~~$(134) million ~~in 2014, $14~~and $(139) million ~~in 2013,~~as of December 31, 2017 and ~~$13 million in 2012.~~2016, respectively.


⁽³⁾	In ~~2014,~~December 2017, TEP ~~entered into agreements to~~completed the purchase ~~certain~~of an undivided ownership interest in the Springerville ~~Coal Handling Facilities leased interests.~~Common Facilities. See Note ~~5 of Notes to Consolidated Financial Statements.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~Utility Plant under Capital Leases~~

All utility plant under capital leases is used in generation operations and amortized over the primary lease term. See Note 5 of Notes to Consolidated Financial Statements. At December 31, 2014, the utility plant under capital leases includes: 1) Springerville Unit 1; 2) Springerville Common Facilities; and 3) Springerville Coal Handling Facilities. The following table shows the amount of lease expense incurred for generation-related capital leases:

Year Ended December 31,
2014 2013 2012
Millions of Dollars
Lease Expense:
Interest Expense – Included in:
Capital Leases $ 10
$ 25
$ 34
Operating Expenses – Fuel 1
2
3
Amortization of Capital Lease Assets – Included in:
Operating Expenses – Fuel 6
5
4
Operating Expenses – Amortization 16
15
14
Total Lease Expense $ 33
$ 47
$ 55

~~Utility plant depreciation rates and approximate average remaining service lives based on the most recent depreciation studies available at December 31, 2014, were as follows:~~

December 31, 2014

Annual Depreciation Rate ⁽³⁾
Average Remaining Life in Years
Major Class of Utility Plant in Service:
Electric Generation Plant ⁽¹⁾
3.31% 22
Electric Transmission Plant 1.48% 32
Electric Distribution Plant ⁽¹⁾
2.08% 35
General Plant ⁽¹⁾
5.48% 11
Intangible Plant ⁽²⁾
Various Various


⁽¹⁾	~~In June 2013,~~6 for additional information regarding the ACC issued the 2013 TEP Rate Order that approved a change in depreciation rates which reflects changes in the remaining average useful lives for our generation, distribution, and general plant assets. See Note 2 of Notes to Consolidated Financial Statements.Springerville leases.


⁽²⁾⁽⁴⁾	The majority of TEP's investment in intangible plant represents computer software, which is being amortized over its expected useful life of three to five years for smaller application software. For large enterprise software, we use the remaining life depreciation method. At December 31, 2014, remaining lives ranged from one to six years.


⁽³⁾	~~The depreciation rates represent~~Represents a composite of the depreciation rates of assets within each major class of utility ~~plant.~~plant and is based on the 2015 depreciation study available for the major classes of Plant in Service. TEP implemented new depreciation rates effective March 1, 2017, as approved in the 2017 Rate Order.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Utility Plant Under Capital Leases

All assets included in Utility Plant Under Capital Leases are used in generation operations and amortized over the primary lease term. The following table shows the amount of lease expense incurred for capital leases:



	Years Ended December 31,
(in millions)	2017		2016		2015
Lease Expense
Interest Expense included in:
Interest Expense, Capital Leases	$	3	$	3	$	4
Amortization of Capital Lease Assets included in:
Operating Expenses, Fuel	—		—		2
Operating Expenses, Amortization	6		5		6
Total Lease Expense	$	9	$	8	$	12

Springerville Acquisitions

In September 2016, TEP purchased an undivided interest in Springerville Unit 1. The purchase increased TEP's total ownership interest to 100%. In December 2017, TEP purchased an undivided interest in the Springerville Common Facilities. As of December 31, 2017, Utility Plant Under Capital Leases represented a 32.2% undivided interest in certain Springerville Common Facilities. See Note 6 for additional information regarding the Springerville capital lease purchases.

JOINTLY-OWNED FACILITIES

AtAs of December 31, ~~2014,~~2017, TEP was a participant in the following jointly-owned ~~generating stations~~generation facilities and transmission ~~systems as follows:~~systems:


	Ownership Percentage	Plant in Service		Construction Work in Progress		Accumulated Depreciation		Net Book Value
		Millions of Dollars
San Juan Units 1 and 2	50.0%	$	453	$	8	$	242	$	219
Navajo Units 1, 2, and 3	7.5%	153		1		112		42
(in millions)										Ownership Percentage	Plant in Service		Construction Work in Progress		Accumulated Depreciation		Net Book Value
San Juan Unit 1										50.0%	$	274	$	6	$	83	$	197
Four Corners Units 4 and 5	7.0%	104		3		77		30		7.0%	113		54		79		88
Luna Energy Facility	33.3%	55		—		2		53
Luna										33.3%	55		—		3		52
Gila River Unit 3	75.0%	186		—		54		132		75.0%	203		3		60		146
Gila River Common Facilities	18.75%	42		—		11		31		18.8%	25		—		8		17
Springerville Coal Handling Facilities										83.0%	202		—		81		121
Transmission Facilities	Various	371		21		193		199		Various	483		5		247		241
Total		$	1,364	$	33	$	691	$	706		$	1,355	$	68	$	561	$	862

In December 2014, TEP completed the purchase of Gila River Unit 3. TEP jointly owns Gila River Unit 3 with UNS Electric, Inc., an affiliated subsidiary of UNS Energy (UNS Electric). See Note 7 of Notes to Consolidated Financial Statements.

As participants in these jointly-owned facilities, TEP is responsible for its share of operating and capital costs for the above facilities. ~~TEP~~The Company accounts for its share of operating expenses and utility plant costs related to these facilities using proportionate consolidation.

~~Springerville~~RETIREMENTS

San Juan Generating Station

In October 2014, the EPA published a final rule approving a SIP covering BART requirements for San Juan, which included the closure of Units 2 and 3 by December 2017. TEP is a participant in San Juan Units 1 and 2. Given the closure of Units 2 and 3 and the desire of certain participants to exit their ownership in San Juan, PNM, TEP, and the other participants negotiated restructured ownership agreements which became effective upon the sale of San Juan Coal Company (SJCC) stock in January 2016. Under the new restructured ownership agreements, TEP and the other remaining participants have the option to exit their remaining ownership interests in San Juan as of June 30, 2022.

In 2017, TEP recorded the early retirement San Juan Unit 12 and applied excess depreciation reserves against the unrecovered NBV as approved in the 2017 Rate Order. The Consolidated Balance Sheets reflect a $224 million decrease in Plant in Service and Accumulated Depreciation and Amortization related to San Juan Unit 2. On December 20, 2017, San Juan Unit 2 was removed from service. See Note 2 for additional information regarding the 2017 Rate Order.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Navajo Generating Station

In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP is currently recovering Navajo's capital and operating costs in base rates using a useful life of 2030. As a result of the planned early retirement of Navajo, $52 million of the facility's NBV and other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of December 31, ~~2014,~~2017. See Note 2 for additional information related to the planned early retirement of Navajo.

Sundt Generating Station

In March 2016, TEP ~~owned 24.7%~~notified the EPA of ~~Springerville Unit~~its decision to permanently eliminate coal as a fuel source to comply with the EPA rules and transferred the NBV of the coal handling facilities at Sundt to a regulatory asset. As approved in the 2017 Rate Order, TEP applied excess depreciation reserves against the regulatory asset as of December 31, 2017. See Note 2 for additional information regarding the 2017 Rate Order.

In 2017, TEP submitted an Air Quality Permit Application (Application) to the Pima County Department of Environmental Quality (PDEQ) related to a generation modernization project at Sundt that will add generation capacity in the form of RICE generators in 2019 and 2020. As part of the Application, TEP plans to early retire Sundt Units 1 and ~~continued to lease~~2 by the ~~remaining portion~~end of 2020. TEP is currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives of 2028 and 2030, respectively. As a result of the ~~facility. Effective January 1, 2015, following completion~~planned early retirement, $31 million of the ~~purchase~~facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Consolidated Balance Sheets as of anDecember 31, 2017. See Note 2 for additional ~~24.8% leased interest in Springerville Unit~~information related to the planned early retirement of Sundt Units 1 and expiration of the lease, TEP has a 49.5% ownership interest in the Springerville Unit 1 generating station and will operate the facility on behalf of third parties, i.e. Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of the remaining two owner participants, Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners). The Third-Party Owners are responsible for their share of operating and capital costs for the facility. See Note 6 of Notes to Consolidated Financial Statements.2.

ASSET RETIREMENT OBLIGATIONS

The accrual of AROs is primarily related to generation and ~~photovoltaic~~PV assets and is included in ~~Deferred Credits~~Regulatory and Other ~~Liabilities~~Liabilities—Other on the ~~balance sheets.~~Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the ~~balance sheets:~~Consolidated Balance Sheets:

December 31,
2014 2013
Millions of Dollars
Beginning Balance $ 22
$ 14
Liabilities Incurred 5
—
Accretion Expense or Regulatory Deferral 1
1
Revisions to the Present Value of Estimated Cash Flows ⁽¹⁾
—
7
Ending Balance $ 28
$ 22



	December 31,
(in millions)	2017			2016
Beginning of Period	$	33		$	32
Liabilities Incurred	3			—
Liabilities Settled	(1		)	—
Regulatory Deferral/Accretion Expense	2			2
Revisions to the Present Value of Estimated Cash Flows ⁽¹⁾	9			(1		)
End of Period	$	46		$	33


⁽¹⁾	Primarily related to changes in expected cost estimates and the acceleration of asset retirement dates of ~~generating~~certain generation facilities.

NOTE 4.ACCOUNTS RECEIVABLE

The following table presents the components of Accounts Receivable, Net on the Consolidated Balance Sheets:



	December 31,
(in millions)	2017			2016
Customer	$	81		$	74
Due from Affiliates (Note 5)	7			9
Unbilled	39			34
Other	16			13
Allowance for Doubtful Accounts	(5		)	(5		)
Accounts Receivable, Net	$	138		$	125

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

NOTE 4. 5.RELATED PARTY TRANSACTIONS

TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including ~~Unisource Energy Services, Inc.,~~ UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy ~~affiliates)~~Affiliates). These transactions include ~~sales~~the sale and ~~purchases~~purchase of power and transmission services, common cost allocations, and the provision of corporate and other labor related services. ~~Additionally, TEP and UNS Electric jointly own a generating station unit. See Note 7 of Notes to Consolidated Financial Statements.~~

The following table ~~summarizes~~presents the components of related party ~~transactions:~~balances included in Accounts Receivable, Net and Accounts Payable on the Consolidated Balance Sheets:

Years Ended December 31,
2014 2013 2012
Millions of Dollars
Wholesale Sales - TEP to UNS Electric ⁽¹⁾
$ 4
$ 1
$ 2
Wholesale Sales - UNS Electric to TEP ⁽¹⁾
4
2
1
Control Area Services - TEP to UNS Electric ⁽²⁾
3
4
3
Common Costs - TEP to UNS Energy Affiliates ⁽³⁾
13
12
12
Supplemental Workforce - UNS Energy Affiliate to TEP ⁽⁴⁾
16
16
17
Corporate Services - UNS Energy to TEP ⁽⁵⁾
14
5
2
Corporate Services - UNS Energy Affiliates to TEP ⁽⁶⁾
1
1
1



	December 31,
(in millions)	2017		2016
Receivables from Related Parties
UNS Electric	$	5	$	7
UNS Gas	2		2
Total Due from Related Parties	$	7	$	9

Payables to Related Parties
SES	$	3	$	2
UNS Energy	1		—
Total Due to Related Parties	$	4	$	2

The following table presents the components of related party transactions included in the Consolidated Statements of Income:



	Years Ended December 31,
(in millions)	2017		2016		2015
Goods and Services Provided by TEP to Affiliates
Transmission Revenues, UNS Electric ⁽¹⁾	$	7	$	7	$	6
Wholesale Revenues, UNS Electric ⁽¹⁾	—		—		2
Control Area Services, UNS Electric ⁽²⁾	3		2		2
Common Costs, UNS Energy Affiliates ⁽³⁾	16		14		12
Corporate Services, Fortis Affiliates ⁽⁴⁾	2		—		—

Goods and Services Provided by Affiliates to TEP
Wholesale Revenues, UNS Electric ⁽¹⁾	—		1		1
Supplemental Workforce, SES ⁽⁵⁾	15		14		16
Corporate Services, UNS Energy ⁽⁶⁾	5		7		7
Corporate Services, UNS Energy Affiliates ⁽⁷⁾	5		4		1


⁽¹⁾	TEP and UNS Electric sell power and transmission services to each ~~other~~other. Wholesale power is sold at prevailing market ~~prices.~~prices while transmission services are sold at FERC approved rates through the applicable Open Access Transmission Tariff.


⁽²⁾	TEP charges UNS Electric for control area services under a ~~FERC-accepted~~FERC-approved Control Area Services Agreement.


⁽³⁾	Common costs ~~(systems,~~(information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. ~~Management believes this~~The method of allocation is ~~reasonable.~~deemed reasonable by management and is reviewed by the ACC as part of the rate case process.


⁽⁴⁾	~~SES~~TEP provides ~~supplemental workforce~~non-tariffed goods and ~~meter-reading~~ services to ~~TEP. Amounts are based on costs~~Fortis affiliate companies at the higher of ~~services performed, and management believes that the charges for the services are reasonable.~~fully burdened cost or fair market value.


⁽⁵⁾	~~Corporate costs~~SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management.

⁽⁶⁾

Costs for corporate services at UNS Energy ~~such as merger costs and legal and audit fees,~~ are allocated to its subsidiaries using the ~~Massachusetts'~~Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately ~~81%~~82% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis Management fees. TEP's share of Fortis' management fees were $6 million in both 2017 and 2016, and $5 million in 2015.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


⁽⁶⁾⁽⁷⁾	~~All Corporate Services~~Costs for corporate services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.

~~At December 31, 2014~~CONTRIBUTION FROM PARENT

UNS Energy made no equity contributions to TEP in 2017 or 2016. TEP received a contribution from UNS Energy of $180 million in 2015. The contributions were used to repay revolving credit loans, redeem bonds, purchase additional generation capacity, and ~~December 31, 2013, our Balance Sheets include the following intercompany balances:~~

provide additional liquidity to TEP.

December 31, 2014 December 31, 2013
Millions of Dollars
Receivables from Related Parties
UNS Electric $ 4
$ 3
UNS Gas 1
2
UNS Energy —
1
Total Due from Related Parties $ 5
$ 6

Payables to Related Parties
SES $ 2
$ 2
UNS Electric 1
—
UNS Energy —
7
Total Due to Related Parties $ 3
$ 9
DIVIDENDS PAID TO PARENT

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~ TEP declared and paid $70 million in dividends to UNS Energy in 2017 and $50 million in both 2016 and 2015.

NOTE 5. 6.DEBT, CREDIT ~~FACILITIES,~~FACILITY, AND CAPITAL LEASE OBLIGATIONS

DEBT

Long-term debt matures more than one year from the date of the financial statements. ~~We summarize TEP’s long-term debt in the statements of capitalization.~~

~~DEBT ISSUANCES AND REDEMPTIONS~~

~~Fixed Rate Notes~~

In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. TEP may redeem the notes prior to September 2043, with a make-whole premium plus accrued interest. After September 2043, TEP may redeem the notes at par plus accrued interest. TEP used the net proceeds to repay approximately $90 million on the outstanding borrowings under the 2010 Revolving Credit Facility with the remaining proceeds used for general corporate purposes. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding.

In September 2012, TEP issued $150 million of 3.85% unsecured notes due March 2023. TEP may call the debt prior to December 2022, with a make-whole premium plus accrued interest. After December 2022, TEP may call the debt at par plus accrued interest. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding. TEP used the net proceeds to repay approximately $72 million outstanding on the 2010 Revolving Credit Facility with the remaining proceeds used for general corporate purposes.

~~Tax-Exempt Fixed Rate Bonds~~

In March 2013, the Industrial Development Authority of Pima County, Arizona issued approximately $91 million aggregate principal amount of unsecured tax-exempt Industrial Development Revenue Bonds (IDRBs) for the benefit of TEP. The bonds bear interest at a fixed rate of 4.0%, mature in September 2029, and may be redeemed at par on or after March 2023. The proceeds from the sale of the bonds were deposited with a trustee to retire approximately $91 million of 6.375% unsecured tax-exempt bonds in April 2013.

~~Tax-Exempt Variable Rate Bonds and Interest Rate Swap~~

In November 2013, the Industrial Development Authority of Apache County, Arizona issued $100 million of tax-exempt, variable rate IDRBs for the benefit of TEP, due April 2032. The lender resets the interest rate monthly based on a percentage of an index rate equal to one-month LIBOR plus a bank margin rate. In 2014, the average monthly variable rate was 0.87% and ranged from 0.85% to 0.95%. In 2013, the average monthly variable rate was 0.95%. These bonds are multi-modal bonds, and the initial term is set at five years through November 2018, at which time the bonds will be subject to mandatory tender for purchase. Proceeds were deposited with a trustee to redeem $100 million variable rate bonds in December 2013.

~~Certain of TEP's tax-exempt, variable rate bonds are supported by Letter of Credits (LOCs) issued under the 2010 Credit Agreement and TEP Reimbursement Agreement, see below.~~

The following table ~~shows interest rates (exclusive~~presents the components of ~~LOC and remarketing fees)~~Long-Term Debt, Net on ~~TEP’s weekly variable rate bonds, which are reset weekly by its remarketing agents:~~

the Consolidated Balance Sheets:

Years Ended December 31,
2014 2013 2012
Interest Rates on Bonds:
Average Interest Rate 0.08% 0.10% 0.17%
Range of Average Weekly Rates .05% - 0.13% 0.06% - 0.25% 0.06% - 0.26%



			December 31,
($ in millions)	Interest Rate	Maturity Date	2017		2016
Notes
2011 Notes	5.15%	2021	$	250	$	250
2012 Notes	3.85%	2023	150		150
2014 Notes	5.00%	2044	150		150
2015 Notes	3.05%	2025	300		300
Tax-Exempt Local Furnishings Bonds
2010 Pima A	5.25%	2040	100		100
2012 Pima A	4.50%	2030	16		16
2013 Pima A	4.00%	2029	91		91
2013 Apache A ⁽¹⁾	1.41%	2032	100		100
Tax-Exempt Pollution Control Bonds
2009 Pima A	4.95%	2020	80		80
2009 Coconino A	5.13%	2032	15		15
2010 Coconino A⁽²⁾	1.76%	2032	37		37
2012 Apache A	4.50%	2030	177		177
Total Long-Term Debt ⁽³⁾			1,466		1,466
Less Unamortized Discount and Debt Issuance Costs			12		13
Less Current Maturities of Long-Term Debt⁽¹⁾			100		—
Total Long-Term Debt, Net			$	1,354	$	1,453

⁽¹⁾

The bonds are variable rate debt for which rates are reset monthly. The interest rate is calculated using a weighted average based on a percentage of an index equal to one-month LIBOR plus a credit spread. The bonds are subject to mandatory tender for purchase in November 2018, and were reclassified to Current Maturities of Long-Term Debt on the Consolidated Balance Sheets as of December 31, 2017.


⁽²⁾	The bonds are variable rate debt for which rates are reset weekly. The interest rate is calculated using a weighted average and includes LOC fees and remarketing fees. The bonds are backed by an LOC issued pursuant to the 2010 Reimbursement Agreement, which expires in February 2019.


⁽³⁾	As of December 31, 2017, all of TEP's debt is unsecured, with the exception of the 2010 Coconino A variable rate bonds, which are backed by an LOC.

In September 2014, an interest rate swap TEP entered into in August 2009, expired. The interest rate swap had the economic effect of converting $50 million of variable rate bonds to a fixed rate of 2.4% from September 2009 to September 2014.

~~TEP MORTGAGE INDENTURE~~

Prior to November 2013, the 2010 Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in mortgage bonds issued under the 1992 Mortgage. As a result of a credit rating upgrade, in October 2013, TEP canceled $423 million in mortgage bonds and discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the 2010 Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured.

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~~CREDIT AGREEMENTS~~

~~2014 Credit Agreement~~DEBT ISSUANCES AND REDEMPTIONS

Fixed Rate Debt

In February 2015, TEP issued and sold $300 million aggregate principal amount of senior unsecured notes. TEP may redeem the notes prior to December ~~2014,~~2024, with a make-whole premium plus accrued interest. On or after December 2024, TEP may redeem the notes at par plus accrued interest.

In January 2015, TEP purchased $130 million aggregate principal amount of unsecured tax-exempt IDRBs issued in June 2008 by the Industrial Development Authority (IDA) of Pima County, Arizona for the benefit of TEP. The bonds were not remarketed and were subsequently retired in September 2017.

Variable Rate Debt

In August 2015, TEP redeemed two series of variable rate tax-exempt bonds at par with an aggregate principal amount of $79 million prior to maturity. In September 2015, TEP terminated the associated LOCs issued under a revolving credit facility.

CREDIT FACILITY

In October 2015, TEP entered into an unsecured credit agreement ~~(2014 Credit Agreement).~~which replaced its previous credit agreements. The ~~2014 Credit Agreement provides for~~credit facility included: (i) a ~~$130~~borrowing capacity of $250 million ~~term loan commitment and a $70 million~~in revolving credit commitment. Any amounts borrowed under the revolving credit commitment can be used for general corporate purposes. Amounts borrowed under the term loan can only be used to purchase certain tax-exempt bonds in lieucommitments; (ii) an LOC facility with a sublimit of ~~redemption. All loans made pursuant to the term loan commitment~~$50 million; and ~~the revolving credit commitment will be due and payable in November 2015, the termination~~(iii) an original maturity date of October 2020 with a provision allowing TEP to request up to twoone-year maturity extensions.

As permitted by the ~~2014 Credit Agreement.~~

In January 2015, amounts borrowed under the term loan commitment were used to purchase $130 million aggregate principal amount of unsecured IDRBs issued in June 2008 for the benefit of TEP. These multi-modal bonds currently bear interest at a fixed rate of 5.750%credit agreement, TEP requested and ~~mature in September 2029. At December 31, 2014, the bonds are classified as Long-Term Debt on TEP's balance sheet.~~

~~Loans under the 2014 Credit Agreement bear interest at a variable interest rate consisting of a spread over LIBOR or Alternate Base Rate. Alternate Base Rate~~was granted twoone-year extensions. The facility's new maturity date is equal to the greater of (i) issuing bank's reference rate, (ii) the federal funds rate plus 1/2 of 1% or (iii) adjusted LIBOR for an interest period of one month plus 0.750%. The interest rate in effect on borrowings is LIBOR plus 0.750% for Eurodollar loans or Alternate Base Rate for Alternate Base Rate loans.

At December 31, 2014, TEP had a $70 million loan balance under the revolving credit facility and no borrowings under the term loan portion of the 2014 Credit Agreement. The revolving loan balance was included in Current Liabilities on TEP’s balance sheets. At December 31, 2014, there was nothing available under the revolving credit facility and $130 million available under the term loan for the 2014 Credit Agreement. As of 01/30/15, TEP had a $130 million term loan balance outstanding under the 2014 Credit Agreement and a $70 million revolving loan balance.

~~2010 Credit Agreement~~

TEP’s core credit facility, which was entered into in 2010 and amended in 2011 (2010 Credit Agreement), has an expiration date of November 2016, and will continue to provide TEP with access to $200 million of revolving credit and $82 million in LOCs supporting variable-rate tax-exempt bonds.October 2022.

Interest rates and fees under the ~~2010 Credit Agreement~~credit facility are based on a pricing grid tied to TEP’s credit ratings. The interest rate currently in effect on borrowings is LIBOR plus ~~1.125%~~1.00% for Eurodollar loans or ~~Alternate Base Rate plus 0.125%~~ABR with no spread for ~~Alternate Base Rate~~ABR loans. ~~The margin rate currently~~

TEP expects that amounts borrowed under the credit agreement will be used for working capital and other general corporate purposes and that LOCs will be issued from time to time to support energy procurement and hedging transactions. As of December 31, 2017, TEP had $35 million borrowings outstanding included in ~~effect~~Current Liabilities on the ~~$82 million LOC facility is 1.125%.~~

At December 31, 2014, TEP had $15 million in borrowings and $1 million outstanding in LOCs issued under the revolving credit facility for the 2010 Credit Agreement. At December 31, 2013, TEP had no borrowings and $1 million outstanding in LOCs issued under the revolving credit facility for the 2010 Credit Agreement. At December 31, 2014,Consolidated Balance Sheets. As of February 14, 2018, there was ~~$185~~$232 million available under the revolving credit ~~facility~~commitments and LOC facilities.

TEP's previous credit agreements provided for ~~the 2010 Credit Agreement. The revolving loan balance was included~~a total of $270 million in Current Liabilities on TEP’s balance sheets. The outstanding LOCs are not shown as liabilities on TEP’s balance sheets. As of 01/30/15, TEP had $170 million available under the 2010 Credit Agreement revolving credit ~~facility.~~commitments, LOCs supporting variable-rate, tax-exempt bonds, and a $130 million term loan commitment, with original expiration dates of November 2016 and November 2015, respectively.

2010 ~~TEP~~ REIMBURSEMENT AGREEMENT

AIn December 2010, a $37 million LOC was issued to support certain variable rate tax-exempt bonds pursuant to the 2010 ~~TEP~~ Reimbursement Agreement. The LOC ~~supports $37 million aggregate principal amount of variable rate tax-exempt bonds that were issued on behalf of TEP in December 2010. In February 2014, TEP amended the agreement to extend the LOC~~has an expiration date ~~from 2014 to~~of February 2019. Fees are payable on the aggregate outstanding amount of the LOC at a rate of ~~1.00%~~0.75% per ~~annum.~~annum based on TEP's current credit ratings.

COVENANT COMPLIANCE

~~The 2014 Credit Agreement, 2010 Credit Agreement, 2010 TEP Reimbursement Agreement, 2013 Covenants Agreement,~~Certain of TEP's credit and ~~certain of our~~ long-term debt agreements contain restrictive covenants, including restrictions on additional indebtedness, liens to secure indebtedness, mergers, sales of assets, transactions with affiliates, and restricted payments.

At As of December 31, ~~2014, we were~~2017, TEP was in compliance with the terms of ~~our~~its credit and long-term debt ~~2014 Credit Agreement, 2010 Credit Agreement, 2013 Covenants Agreement, and~~agreements.

CAPITAL LEASE OBLIGATIONS

The following table details Capital Lease Obligations on the ~~2010 TEP Reimbursement Agreement.~~Consolidated Balance Sheets:



	December 31,
(in millions)	2017		2016
Capital Lease Obligations	$	39	$	91
Less Current Obligations Under Capital Leases	11		52
Total Capital Lease Obligations, Non-Current	$	28	$	39

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

~~CAPITAL LEASE OBLIGATIONS~~

~~In January 2015, TEP reduced its capital lease obligations through the scheduled purchase payment for Springerville Unit 1 of $43 million and scheduled payments on other leases of $9 million.~~

Springerville Unit 1 Capital Lease Purchases

~~The Springerville Unit 1 Leases had an initial term to~~In January 2015, ~~and included a fair market value purchase option at the end~~upon expiration of the ~~initial~~ lease ~~term.~~

In December 2014, TEP purchased a 10.6% leased interest in Springerville Unit 1, representing 41 MW of capacity, for $20 million, the appraised value. Upon purchase, TEP reduced Capital Lease Obligations on its balance sheet for the purchase price. In January 2015,term, TEP purchased leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million, the appraised value.

With the completion of ~~these lease option purchases,~~the purchase, TEP ~~owns~~owned 49.5% of Springerville Unit 1, or 192 MW of capacity. ~~Furthermore,~~

In September 2016, TEP ~~is obligated~~purchased the remaining undivided interest in Springerville Unit 1 for $85 million, bringing its total ownership of the assets to ~~operate the unit for the Third-Party Owners under an existing facility support agreement. The Third-Party Owners are obligated~~100% and total generating capacity to compensate TEP for their pro rata share of expenses for the unit in the amount of approximately $1.5 million per month and their share of capital expenditures, which are approximately $7 million in 2015.387 MW. See Note ~~6 of Notes~~7 for more information regarding the settlement agreement relating to ~~Consolidated Financial Statements~~.Springerville Unit 1.

Springerville Coal Handling Facilities Lease Purchase ~~Commitment~~

In April ~~2014,~~2015, upon expiration of the lease term, TEP ~~notified the owner participants and their lessors that TEP has elected to purchase their~~purchased an 86.7% undivided ownership ~~interests~~interest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million, ~~upon the expiration~~bringing its total ownership of the ~~lease term in April 2015. Due~~assets to ~~TEP’s~~100%. Upon purchase commitment, in April 2014, TEP recorded an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheet in the amount of $109 million, which represented the present value of the ~~total~~leased interest, TEP reduced Capital Lease Obligations on the Consolidated Balance Sheets for the purchase ~~commitment.~~price.

~~Upon TEP's purchase,~~In May 2015, SRP, ~~is obligated to buy~~the owner of Springerville Unit 4, purchased from TEP a ~~portion of~~17.05% undivided interest in the Springerville Coal Handling Facilities ~~from TEP~~ for approximately $24 million, and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. No amounts have been recorded for these commitments from SRP and Tri-State at December 31, 2014.million.

Springerville Common Facilities Leases

~~The~~As of December 31, 2017, the Springerville Common Facilities Leases ~~have an initial term to December 2017 for one lease and January 2021 for the other~~include two leases ~~subject to optional renewal~~with a total fixed price purchase options of $68 million and initial terms ending January 2021.

Under the two leases, TEP has options to: (i) renew the leases for periods of two or more ~~years through 2025. Instead of extending~~years; or (ii) exercise the ~~leases,~~fixed price purchase options under these contracts. In addition, TEP ~~may exercise a fixed-price purchase provision. The fixed prices for the acquisition of the common facilities are $38 million in 2017 and $68 million in 2021.~~

~~TEP agreed~~entered into agreements with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that contain the following conditions if the ~~Springerville Coal Handling Facilities and~~ Common Facilities Leases are not ~~renewed,~~renewed: (i) TEP will exercise the purchase options under these ~~contracts.~~contracts; (ii) SRP will ~~then~~ be obligated to buy a ~~portion of these facilities~~14% undivided interest in the facilities; and (iii) Tri-State will ~~then~~ be obligated to either: (a) buy a ~~portion of these~~14% undivided interest in the facilities; or (b) continue ~~making~~to make payments to TEP for the use of these facilities.

In December 2017, TEP purchased a 17.8% undivided interest in the Springerville Common Facilities for$38 million, bringing its total ownership of the assets to 67.8%. Upon purchase of the leased interest, TEP reduced Current Lease ~~Debt and Equity~~

~~Investments in Springerville Lease Debt and Equity~~

~~In January 2013, TEP received the final maturity payment of $9 million~~Obligations on the ~~investment in Springerville Unit 1 lease debt. TEP also held an undivided equity ownership interest in the Springerville Unit 1 Leases totaling~~Consolidated Balance Sheets by $36 ~~million at December 31, 2013. At December 31, 2014, $36 million was transferred from Lease Equity Investment to Plant in Service on TEP's balance sheet.~~million.

~~Interest Rate Swap—~~Springerville Common Facilities Lease ~~Debt~~Interest Rate Swap

~~TEP’s~~TEP entered into an interest rate swap agreement in 2006 that hedges a portion of the floating interest rate risk associated with the Springerville Common Facilities lease debt. ~~Interest on the lease debt is payable at six-month LIBOR plus a credit spread. The applicable spread was 1.75% at December 31, 2014 and December 31, 2013.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

The swap has the effect of fixing the ~~interest rates~~benchmark LIBOR rate on a portion of the amortizing principal ~~balances~~balance. The swap matures in January 2020 with interest on the lease debt payable at a swapped rate of 5.77% plus an applicable margin per the lease agreement. The lease debt outstanding as ~~follows:~~

of December 31, 2017 consisted of a notional amount of $18 million on which interest was fixed by the swap and a notional amount of $3 million of debt that was not hedged. The applicable margin was 1.88% as of December 31, 2017 and 2016.

Lease Debt Outstanding at December 31, 2014
Fixed
Rate

LIBOR
Spread
Notional Amount $32 million - Effective Date June 2006 5.77 % 1.75 %

TEP recorded the interest rate swap as a cash flow hedge for financial reporting purposes. See Cash Flow Hedges in Note 1011 for additional information.

Table of ~~Notes to Consolidated Financial Statements.~~Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

DEBT MATURITIES

Long-term debt, including ~~term loan payments,~~ revolving credit facilities classified as long-term, and capital lease obligations mature on the following dates:


	Long-Term Debt Maturities ⁽¹⁾		Capital Lease Obligations			Total
	Millions of Dollars
2015	$	—	$	188		$	188
2016	79		16			95
2017	—		18			18
(in millions)									Long-Term Debt⁽¹⁾		Capital Lease Obligations			Total Debt Maturities⁽²⁾
2018	100		11			111			$	100	$	11		$	111
2019	37		12			49			37		11			48
Total 2015 - 2019	216		245			461
2020									80		18			98
2021									250		—			250
2022									—		—			—
Total 2018 - 2022									467		40			507
Thereafter	1,159		18			1,177			999		—			999
Less: Imputed Interest	—		(20		)	(20		)	—		(1		)	(1		)
Total	$	1,375	$	243		$	1,618		$	1,466	$	39		$	1,505

⁽¹⁾

$~~115~~37 million of TEP’s variable rate bonds are backed by ~~LOCs~~an LOC issued pursuant to the ~~2010 Credit Agreement, which expires in November 2016, and the TEP~~ 2010 Reimbursement Agreement, which expires in ~~December~~February 2019. Although the variable rate ~~bonds mature between 2022 and~~bond matures in 2032, the above table reflects a redemption or repurchase of such ~~bonds~~bond in ~~2016 and~~ 2019 as though the ~~LOCs terminate~~LOC terminates without replacement upon expiration of ~~the 2010 Credit Agreement and~~ the 2010 Reimbursement Agreement. TEP's 2013 tax-exempt variable rate IDRBs, which have an aggregate principal amount of $100 million and mature in 2032, are subject to mandatory tender for purchase in November 2018. ~~The repayment~~


⁽²⁾	Total long-term debt excludes $10 million of ~~TEP Unsecured Notes is not reduced by the remaining~~related unamortized debt issuance costs and $2 million of unamortized original issue discount.

NOTE 6. 7.COMMITMENTS ~~CONTINGENCIES,~~ AND ~~ENVIRONMENTAL MATTERS~~CONTINGENCIES

COMMITMENTS

AtAs of December 31, ~~2014,~~2017, TEP had the following firm, non-cancellable, minimum purchase obligations and operating ~~leases.~~leases:


	2015		2016		2017		2018		2019		Thereafter		Total
	Millions of Dollars
(in millions)															2018		2019		2020		2021		2022		Thereafter		Total
Fuel, Including Transportation	$	76	$	78	$	76	$	49	$	49	$	285	$	613	$	82	$	83	$	73	$	43	$	24	$	244	$	549
Purchased Power	22		7		—		—		—		—		29		29		—		—		—		—		—		29
Transmission	6		6		6		6		4		16		44		19		19		8		4		1		8		59
Renewable Power Purchase Agreements	45		45		45		45		44		565		789		64		64		63		63		63		668		985
RES Performance-Based Incentives	8		8		8		8		8		76		116		8		8		7		7		7		46		83
Operating Leases:
Operating Leases ⁽¹⁾															1		1		1		1		1		3		8
Land Easements and Rights-of-Way	2		1		1		1		2		77		84		1		1		1		2		2		82		89
Operating Leases Other	1		1		1		1		1		5		10
Total Purchase Commitments	$	160	$	146	$	137	$	110	$	108	$	1,024	$	1,685	$	204	$	176	$	153	$	120	$	98	$	1,051	$	1,802


⁽¹⁾	Primarily represents leases for land, rail cars, and office facilities with varying terms, provisions, and expiration dates through 2036. TEP's operating lease expense totaled $1 million in 2017, $2 million in 2016, and $3 million in 2015.

Costs for Purchased Power, Transmission, and Fuel, Including Transportation, are recoverable from customers through the PPFAC mechanism. A portion of the costs of PPAs are recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. PBIs costs are recoverable through the RES tariff. See Note 2 for information on ACC approved cost recovery mechanisms.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

Fuel, Including Transportation

TEP has long-term ~~contracts~~agreements for the purchase and delivery of coal with various expiration dates ~~through~~between 2020 and 2031. Amounts paid under these contracts depend on actual quantities purchased and delivered. Some of these ~~contracts~~agreements include a price adjustment ~~clause~~components 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.~~costs.

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These ~~contracts~~agreements expire in various years between ~~2017~~2018 and 2040. In January 2018, TEP entered into a transportation agreement with EPNG extending the expiration date of the existing agreement from April 2018 to April 2023. Estimated future payments not included in the table above are: $4 million in 2018; $5 million in 2019 through 2022; and $1 million through the end of the contract.

Purchased Power ~~and Transmission~~

TEP has ~~agreements~~contracts with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. In general, these contracts provide for capacity ~~payments~~ and energy payments based on actual power taken under the ~~contracts. These~~ contracts ~~expire~~with various expiration dates through ~~2017.~~the fourth quarter of 2018. Certain of these contracts are at a fixed price per MW and others are indexed to natural gas prices. The commitment amounts included in the table above are based on projected market prices as of December 31, ~~2014.~~2017.

Transmission

TEP has agreements with other utilities to ~~provide~~purchase transmission ~~services.~~services over lines that are part of the Western Interconnection, a regional grid in the United States. These ~~contracts~~agreements expire in various years between ~~2018~~2019 and ~~2028.~~

~~TEP's purchased power and transmission costs are recoverable from customers through the PPFAC mechanisms.~~2030.

Renewable Power Purchase Agreements ~~and RES Performance-Based Incentives~~

TEP ~~has entered~~enters into ~~20 year Renewable~~long-term renewable PPAs which require TEP to purchase 100% of ~~the output of~~ certain renewable energy generation facilities ~~that have achieved~~output once commercial ~~operation.~~operation status is achieved. While TEP is not required to make payments under the agreements if power is not delivered, estimated future payments are included in the table above. These agreements ~~have~~expire in various ~~expiration dates through 2034. TEP has entered into additional long-term renewable PPAs to comply with~~ years between 2027 and 2036.

RES requirements; however, TEP’s obligation to purchase power under these agreements does not begin until the facilities are operational. A portion of the cost of renewable energy is recoverable through the PPFAC, with the balance of costs recoverable through the RES tariff. See Note 2 of Notes to Consolidated Financial Statements.Performance-Based Incentives

TEP has entered into REC purchase agreements to purchase the environmental attributes from retail customers with solar installations. Payments for the RECs are termed ~~Performance-Based Incentives (PBIs)~~PBIs and are paid in contractually agreed-upon intervals (usually quarterly) based on metered renewable energy production. ~~PBIs are recoverable through the RES tariff. See Note 2 of Notes to Consolidated Financial Statements.~~These agreements expire in various years between 2020 and 2034.

~~Operating Leases~~Land Easements and Rights-of-Way

~~Our operating lease expense is primarily for rail cars, office facilities, land easements,~~Land Easements and ~~rights-of-way with~~Rights-of-Way have varying terms and provisions, and various expiration ~~dates. TEP's operating lease expense totaled $3 million in 2014, and $2 million in each of 2013 and 2012.~~

~~CONTINGENCIES~~

~~Navajo Generating Station Lease Extension~~

~~Navajo Generating Station (Navajo) is located on a site that is leased from~~dates through 2054. In November 2017, the Navajo Nation ~~with~~approved an ~~initial lease term through 2019.~~extension for the use of their land. The extension, signed by TEP and the co-owners of Navajo, commences in December 2019 and ends in December 2054. The Navajo Nation ~~signed a lease amendment that would extend~~has until December 2018 to select one of five different rental payments options provided for in the ~~lease~~extension. The table above includes TEP's 7.5% ownership share of the option which, in management's opinion, is most probable to occur. The total obligation estimated under this option is $8 million commencing in 2019 through 2053. Under the remaining payment options, TEP's share of estimated total payment obligation ranges from $3 million to $8 million with various payment schedules with dates ranging from 2019 through ~~2044. The participants in Navajo, including~~ 2053.

CONTINGENCIES

Legal Matters

TEP ~~have not signed the lease amendment. Certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations are ongoing, and all parties will likely agree~~is party to ~~the terms. To become effective, this lease amendment must be signed by all~~a variety of legal actions arising out of the ~~participants, approved by the Department~~normal course of ~~the Interior,~~business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its consolidated financial results. TEP is ~~subject~~also involved in other kinds of legal actions, some of which assert or may assert claims or seek to ~~environmental reviews.~~impose fines, penalties, and other costs in substantial amounts on TEP ~~owns 7.5% of Navajo~~ and ~~in December 2014, recorded additional lease expense of approximately $2 million related to the lease extension in Deferred Credits and Other Liabilities—Other on TEP's balance sheet.~~are disclosed below.

Claims Related to Springerville Generating Station Unit 1

~~On November 7, 2014,~~In February 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (Agreement). In September 2016, TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased the Third-Party ~~Owners filed a complaint (FERC Action) against~~Owners’ undivided interest in Springerville Unit 1 for $85 million. As also provided for in the Agreement, TEP ~~at the FERC alleging that TEP had not agreed to wheel power and energy for~~received $12.5 million from the Third-Party Owners in full satisfaction of all previously unreimbursed operating costs, which TEP recorded in Operating Revenues—Other on the ~~manner specified in~~Consolidated Statements of Income. Following the ~~Springerville Unit 1 facility support agreement~~purchase, all outstanding disputes, pending litigation, and arbitration proceedings between TEP and the Third-Party Owners and for the cost specified by the Third-Party Owners. The Third-Party Owners requested an order from the FERC requiring such wheeling of the Third-Party Owners’ energy from their Springerville Unit 1 interests beginning on January 1 2015 to the Palo Verde switchyard and for thewere dismissed with prejudice.

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price specified by the Third-Party Owners. On December 3, 2014, TEP filed an answer to the FERC Action denying the allegations and requesting that the FERC dismiss the complaint. On February 19, 2015, the FERC issued an order denying the Third-Party Owners complaint.

On December 19, 2014, the Third-Party Owners filed a complaint against TEP in the Supreme Court of the State of New York, New York County (New York Action), alleging, among other things, that TEP has refused to comply with the Third-Party Owners' instructions to schedule their entitlement share of power and energy, that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases, that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action and that TEP has breached fiduciary duties claimed to be owed to the Third-Party Owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial and the Third-Party Owners’ fees and expenses.

On December 22, 2014, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent a notice to TEP that alleges that TEP has defaulted under the Third-Party Owners’ leases. The notice states that the Owner Trustees, as Lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totaling approximately $71 million. On January 26, 2015, Wilmington Trust Company sent a second notice repeating the allegations in the December 22, 2014 notice.

TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners.

Claims Related to San Juan Generating Station

San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.WildEarth Guardians

In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.

~~In February~~ 2013, WildEarth Guardians (WEG) filed a Petition for Review in the ~~United States~~U.S. District Court for the District 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~~including two issued in ~~the WEG Petition, two concern SJCC’s~~2008 related to SJCC 's San Juan mine. ~~WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG~~The petition alleges various National Environmental Policy Act (NEPA) violations against the OSM, ~~including, but not limited to, OSM’s alleged~~including: (i) failure to provide requisite public notice and ~~participation, alleged~~participation; and (ii) failure to analyze certain environmental ~~impacts, and alleged reliance on outdated and insufficient documents.~~impacts. 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 they can demonstrate compliance with the NEPA, ~~has been demonstrated,~~ and enjoining operations at the ~~seven~~affected mines. SJCC intervened in this ~~matter. The Court~~matter and was granted ~~SJCC’s~~its motion to sever its claims from the lawsuit and transfer venue to the ~~United States~~U.S. District Court for the District of New Mexico, where this matter is now ~~proceeding. If WEG ultimately obtains~~pending. In July 2016, the ~~relief it has requested, such~~federal defendants filed a ~~ruling could require significant expenditures~~motion asking that the matter be voluntarily remanded to ~~reconfigure operations at~~ the ~~San Juan mine,~~OSM so the OSM may prepare a new environmental impact statement (EIS) under the ~~production of coal, and impact~~NEPA regarding the ~~economic viability~~impacts of the San Juan Mine mining plan approval. In August 2016, the court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provides that: (i) the OSM’s decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 31, 2019, then the approved mine ~~and San Juan.~~plan will immediately be vacated, absent further court order. TEP cannot currently predict the outcome of this matter or the range of its potential impact.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

Claims Related to Four Corners Generating Station

~~In October 2011, EarthJustice, on behalf of~~Endangered Species Act

On April 20, 2016, several environmental ~~organizations,~~groups filed a lawsuit in the ~~United States~~U.S. District Court for the District of ~~New Mexico~~Arizona against ~~Arizona Public Service Company (APS)~~the OSM and other federal agencies under the Endangered Species Act (ESA) alleging that the OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the U.S. Department of the Interior’s review processnecessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. This review process also required separate environmental impact evaluations under the NEPA and culminated in the issuance of a Record of Decision justifying the agency action extending the life of Four Corners and the ~~other Four Corners Generating Station (Four Corners) participants alleging violations of~~adjacent Navajo Mine. In addition, the ~~Prevention of Significant Deterioration (PSD) provisions of~~lawsuit alleges that these federal agencies violated both the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things,ESA and the ~~plaintiffs seek~~NEPA in providing the federal approvals necessary to ~~have the court issue an order to cease~~extend operations at Four Corners ~~until any required PSD permits are issued~~ and ~~order the payment~~Navajo Mine past July 6, 2016. The lawsuit seeks various forms of ~~civil penalties,~~relief, including a ~~beneficial mitigation project.~~finding that the federal defendants violated the ESA and the NEPA by issuing the Record of Decision, setting aside and remanding the Biological Opinion and Record of Decision, and enjoining the federal defendants from authorizing any elements of the Four Corners and Navajo Mine pending compliance with NEPA. In ~~April 2012,~~July 2016, the defendants answered the complaint and APS, ~~filed motions to dismiss with~~ the court for all claims asserted by EarthJustice in the amended complaint. The parties exchanged settlement proposals in January and February 2015, and have agreed to have the matter stayed until March 31, 2015 to make continued progress toward a final agreement that would resolve this matter without further litigation.

~~TEP owns 7%~~operator of Four Corners, ~~Units 4 and 5 and is liable for its share of any resulting liabilities. TEP's estimated share of the settlement offer submitted by APS~~filed a motion to intervene in this matter. APS’ motion was granted in August ~~2014 is less than $1 million.~~2016. In September 2016, Navajo Transitional Energy Company, LLC (NTEC), the company that owns the Navajo Mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC’s tribal sovereign immunity. In September 2017, the court granted NTEC’s motion to dismiss and dismissed the case with prejudice. In November 2017, the plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit the District Court’s decision to dismiss the case. TEP cannot currently predict the ~~final~~ outcome of ~~the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for~~ this ~~claim, TEP cannot determine estimates of~~matter or the range of ~~costs at this time.~~

In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. In December 2013, the coal supplier and Four Corners’ operating agent filed a claim contesting the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. The New Mexico Taxation and Revenue Department and APS continue with settlement negotiations. TEP cannot predict the outcome or timing of resolution of this claim.potential impact.

Mine ~~Closure~~ Reclamation at Generating ~~Stations~~Facilities Not Operated by TEP

TEP pays ongoing mine reclamation costs related to coal mines that supply ~~generating stations~~generation facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be ~~$49~~$61 million upon expiration of the coal supply agreements, which expire between ~~2017~~2019 and 2031. The Consolidated Balance Sheets reflect a total liability related to reclamation ~~liability (present value~~ of ~~future liability) recorded was $22~~$34 million atand $26 million as of December 31, ~~2014~~2017 and ~~$18 million at December 31, 2013.~~2016, respectively.

Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the ~~credit-adjusted risk-free interest rate to be used to discount future liabilities.~~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 usthe Company to pass through final mine reclamation costs, as a component of fuel ~~cost,~~costs, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

~~Discontinued Transmission Project~~

TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. At this time, TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC that recent transmission additions by TEP and UNS Electric support elimination of this project. TEP and UNS Electric plan to maintain the Certificate of Environmental Compatibility (CEC) previously granted by the ACC for this project in contemplation of using a greater part of the route to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from the FERC before seeking rate recovery from the ACC. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery in TEP's next FERC rate case.

~~Performance Guarantees~~

The participants in each of the remote generating stations in which TEP participates, including TEP, have guaranteed certain performance obligations of the other participants. Specifically, in the event of payment default of a participant, the non-

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~~defaulting~~FERC Compliance

In 2015 and 2016, TEP self-reported to the FERC Office of Enforcement (OE) that the Company had not timely filed certain FERC-jurisdictional agreements. TEP conducted comprehensive internal reviews of its compliance with the FERC filing requirements (Compliance Reviews), and made compliance filings with the FERC Office of Energy Market Regulation. This included the filing of several TSAs entered into between 2003 and 2015 that contained certain deviations from TEP’s standard service agreement form.

In 2016, as a result of the FERC Refund Orders and ongoing discussions with the OE, TEP recorded a liability for the time-value refunds with a corresponding offset in revenues on its financial statements in 2016. In 2016, Wholesale Revenues on the Consolidated Statements of Income reflected $22 million, and, as of December 31, 2016, Current Liabilities—Other on the Consolidated Balance Sheets reflected $5 million related to the time-value refunds.

In June 2016, to preserve its rights, TEP petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the FERC Refund Orders. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement regarding the FERC Refund Orders. In accordance with the agreement, the counterparty paid TEP $8 million, which TEP recorded in Other Income on the Consolidated Statements of Income and dismissed the appeal with prejudice in January 2017.

In May 2017, the FERC informed TEP that: (i) no further enforcement actions were necessary regarding the late-filed TSAs; and (ii) the related investigation was closed. As management no longer believed a loss was probable, TEP reversed the $5 million remaining balance related to potential time-value refunds in Current Liabilities—Other on the Consolidated Balance Sheets, offsetting Wholesale Revenues on the Consolidated Statements of Income.

Performance Guarantees

TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and Luna. The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear aits 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~~generation capacity of the defaulting ~~participants.~~participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of December 31, ~~2014,~~2017, there have been no such payment defaults under any of the ~~remote generating station~~participation agreements. ~~TEP's joint~~The Navajo participation ~~agreements expire~~agreement expires in ~~2016 through 2046.~~

~~ENVIRONMENTAL MATTERS~~

~~Environmental Regulation~~

~~The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO~~₂), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP capitalized $11 million in 2014, $5 million in 2013, and $2 million in 2012 in construction costs to comply with environmental requirements. TEP expects to capitalize environmental compliance costs of $28 million in 2015 and $19 million in 2016. In addition, TEP recorded O&M expenses of $5 million in 2014, $8 million in 2013, and $15 million in 2012. TEP expects environmental O&M expenses to be $4 million in each of 2015 and 2016.

TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.

~~Hazardous Air Pollutant Requirements~~

In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics Standards (MATS) rules, additional emission control equipment will be required by April 2015. TEP, as operator of Springerville and Sundt, and the operator of Navajo have received extensions until April 2016 to comply with the MATS rules. TEP's share of the estimated costs to comply with the MATS rules includes the following:

Estimated Mercury Emissions Control Costs: Navajo
Springerville⁽¹⁾
Millions of Dollars
Capital Expenditures $ 1
$ 5
Annual O&M Expenses 1
1

⁽¹⁾

Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP owns 49.5% of Springerville Unit 1 with the close of the lease option purchases in December 2014 and January 2015; Third-Party Owners are responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP continues to be responsible for 100% of environmental costs attributable to Springerville Unit 2.

TEP expects Four Corners, Sundt, and San Juan's current emission controls to be adequate to comply with the EPA's MATS rules. Therefore, TEP expects no additional capital expenditures or O&M expenses will be incurred to comply. Although expected to be compliant, Sundt would be required to install additional monitoring equipment, at an estimated cost of less than $1 million, to continue to burn coal after the MATS rules become effective.

~~Regional Haze Rules~~

The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on land leased from the Navajo Nation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.

In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install selective catalytic reduction (SCR). Complying with the EPA’s BART rules, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018. TEP cannot predict the ultimate outcome of these matters.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~

~~TEP's estimated costs involved in meeting these rules are:~~

Estimated NOx Emissions Control Costs:
Navajo⁽¹⁾

San Juan ⁽²⁾

Four Corners⁽³⁾

Sundt⁽⁴⁾
Millions of Dollars
Capital Expenditures $ 28
$ 37
$ 35
$ 12
Annual O&M Expenses 1
1
2
5-6

⁽¹⁾

In August 2014, the EPA published a final FIP wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. The plant has until December 2019, to notify the EPA which option will be implemented. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $28 million with O&M on the baghouses expected to be less than $1 million per year.

⁽²⁾

In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of selective non-catalytic reduction (SNCR) and Balance Draft technology on Units 1 and 4 by February 2016. Prior to the shutdown of any units at San Juan, Public Service Company of New Mexico (PNM), the operator, must first obtain New Mexico Public Regulation Commission approval. TEP owns 50% of San Juan Unit 2. At December 31, 2014, the net book value of TEP's share in San Juan Unit 2 was $110 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2.


⁽³⁾	In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.

⁽⁴⁾

In June 2014, the EPA issued a final rule that would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At December 31, 2014, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities.

~~NOTE 7. PURCHASE OF GAS-FIRED GENERATION FACILITY~~

On December 10, 2014, TEP and UNS Electric acquired Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW located in Gila Bend, Arizona, from a subsidiary of Entegra Power Group LLC. TEP purchased a 75% undivided interest in Gila River Unit 3 (413 MW) for $164 million, and UNS Electric purchased the remaining 25% undivided interest. Upon the closing of the transaction, the letter of credit TEP provided in June 2014 for $15 million was canceled.

~~TEP’s purchase of Gila River Unit 3 is intended to replace the reduction of 195 MW of output from Springerville Unit 1 and the 170 MW of capacity expected to be retired at~~ San Juan in ~~2017.~~

~~The transaction has been accounted for using the acquisition method of accounting which requires that assets acquired~~2022, Four Corners in 2041, and ~~liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the assets acquired and liabilities assumed as of the acquisition date:~~

Millions of Dollars
Utility Plant - Net $ 163
Materials and Supplies 2
ARO Obligation Assumed ⁽¹⁾
(1 )
Total Purchase Price $ 164


⁽¹⁾	~~The ARO obligation was recorded at net present value in Deferred Credits and Other Liabilities - Other on TEP's balance sheet.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)~~ Luna in 2046.

NOTE 8.EMPLOYEE BENEFIT PLANS

PENSION BENEFIT PLANS

~~We sponsor two~~TEP has three noncontributory, defined benefit pension ~~plans for substantially all employees and certain affiliate employees.~~plans. Benefits are based on years of service and average compensation. ~~We fund~~Two of the ~~pension~~plans cover the majority of TEP's employees. The Company funds those plans by contributing at least the minimum amount required under Internal Revenue Service (IRS) regulations.

We TEP also ~~maintain~~maintains a ~~Supplemental Executive Retirement Plan (SERP)~~SERP for executive management.

OTHER ~~RETIREE BENEFIT PLANS~~POSTRETIREMENT BENEFITS PLAN

TEP provides limited ~~health care~~healthcare and life insurance benefits for retirees. Active TEP employees may become eligible for these benefits if they reach retirement age while working for TEP or an affiliate.

TEP funds its other ~~retiree~~postretirement benefits for classified employees through a ~~Voluntary Employee Beneficiary Association (VEBA).~~VEBA. TEP contributed $3 million in ~~each of 2014, 2013~~2017, $2 million in 2016, and ~~2012~~$4 million in 2015 to the VEBA. Other ~~retiree~~postretirement benefits for unclassified employees are self-funded.

TEP’s other retiree benefit plan was amended in 2012 to increase the participant contributions for classified employees who retire after February 1, 2014. The effect on the benefit obligation was less than $1 million.

REGULATORY RECOVERY

~~We record~~TEP records changes in ~~our~~ non-SERP pension ~~plans~~ and other ~~retiree~~postretirement defined benefit ~~plan,~~plans, not yet reflected in net periodic benefit cost, as a regulatory asset, as such amounts are probable of future recovery in the rates charged to retail customers. Changes in the SERP obligation, not yet reflected in net periodic benefit cost, are recorded in Other Comprehensive Income since SERP expense is not currently recoverable in rates.

~~The pension and other retiree benefit related amounts (excluding tax balances) included on our balance sheet are:~~

Pension Benefits
Other Retiree
Benefits
Years Ended December 31,
2014 2013 2014 2013
Millions of Dollars
Regulatory Pension Asset Included in Other Regulatory Assets $ 117
$ 71
$ 9
$ 4
Accrued Benefit Liability Included in Accrued Employee Expenses (1 ) (1 ) (2 ) (2 )
Accrued Benefit Liability Included in Pension and Other Retiree Benefits (71 ) (23 ) (67 ) (62 )
Accumulated Other Comprehensive Loss (related to SERP) 5
2
—
—
Net Amount Recognized $ 50
$ 49
$ (60 ) $ (60 )

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table presents pension and other postretirement benefit amounts (excluding tax balances) included on the Consolidated Balance Sheets:



	Pension Benefits						Other Postretirement Benefits
	December 31,
(in millions)	2017			2016			2017			2016
Regulatory Assets	$	121		$	123		$	5		$	5
Accrued Employee Expenses	(1		)	(1		)	(2		)	(2		)
Pension and Other Postretirement Benefits	(71		)	(69		)	(63		)	(63		)
Accumulated Other Comprehensive Loss, SERP	9			6			—			—
Net Amount Recognized	$	58		$	59		$	(60	)	$	(60	)

OBLIGATIONS AND FUNDED STATUS

WeThe Company measured the actuarial present values of all defined benefit pension and other postretirement benefit obligations ~~and other retiree benefit plans at~~as of December 31, ~~2014~~2017 and ~~December 31, 2013.~~2016. The table below ~~includes~~presents the status of all of TEP’s pension and other postretirement benefit plans. All plans have projected benefit obligations in excess of the fair value of plan assets for each period ~~presented. The status of our pension benefit and other retiree benefit plans are summarized below:~~presented:

Pension Benefits
Other Retiree
Benefits
Years Ended December 31,
2014 2013 2014 2013
Millions of Dollars
Change in Projected Benefit Obligation
Benefit Obligation at Beginning of Year $ 330
$ 357
$ 74
$ 77
Actuarial (Gain) Loss 67
(35 ) 5
(5 )
Interest Cost 16
14
3
3
Service Cost 10
11
4
3
Benefits Paid (16 ) (17 ) (5 ) (4 )
Projected Benefit Obligation at End of Year 407
330
81
74
Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year 307
275
10
7
Actual Return on Plan Assets 35
27
1
1
Benefits Paid (16 ) (17 ) (5 ) (4 )
Employer Contributions (1) 9
22
6
6
Fair Value of Plan Assets at End of Year 335
307
12
10
Funded Status at End of Year $ (72 ) $ (23 ) $ (69 ) $ (64 )



	Pension Benefits						Other Postretirement Benefits
	Years Ended December 31,
(in millions)	2017			2016			2017			2016
Change in Benefit Obligation
Beginning of Period	$	424		$	394		$	79		$	78
Actuarial Loss	42			20			1			—
Interest Cost	15			15			2			2
Service Cost	13			12			4			4
Benefits Paid	(19		)	(17		)	(4		)	(5		)
End of Period	475			424			82			79
Change in Fair Value of Plan Assets
Beginning of Period	354			336			14			13
Actual Return on Plan Assets	59			27			2			1
Benefits Paid	(19		)	(17		)	(4		)	(5		)
Employer Contributions ⁽¹⁾	9			8			5			5
End of Period	403			354			17			14
Funded Status at End of Period	$	(72	)	$	(70	)	$	(65	)	$	(65	)


⁽¹⁾	~~In 2015,~~ TEP expects to contribute ~~$23~~$11 million to the pension ~~plans.~~plans in 2018.

The following table provides the components of TEP’s regulatory assets and accumulated other comprehensive loss that have not been recognized as components of net periodic benefit cost as of the dates presented:


	Pension Benefits				Other Retiree Benefits						Pension Benefits				Other Postretirement Benefits
	Years Ended December 31,										Years Ended December 31,
	2014		2013		2014			2013
	Millions of Dollars
(in millions)											2017		2016		2017			2016
Net Loss	$	118	$	74	$	11		$	6		$	129	$	128	$	5		$	6
Prior Service Cost (Benefit)	4		—		(2		)	(2		)	1		—		(1		)	(1		)

The accumulated benefit obligation aggregated for all pension plans is ~~$365~~$428 million atand $384 million as of December 31, ~~2014~~2017 and ~~$297 million at December 31, 2013.~~

Information for Pension Plans with Accumulated Benefit Obligations in excess of Pension Plan Assets:
December 31,
2014 2013
Millions of Dollars
Accumulated Benefit Obligation at End of Year $ 365
$ 13
Fair Value of Plan Assets at End of Year 335
—

~~Only~~2016, respectively. Two of the SERP, which is unfunded, had accumulated benefit obligations in excess of plan assets at December 31, 2013. Due to decreases in discount rates, and changes in mortality projections which reflect a longer life expectancy, all of ourpension plans had accumulated benefit obligations in excess of plan assets atas of December 31, ~~2014.~~2017, compared to three as of December 31, 2016, as a result of market gains on plan assets in 2017. The following table

7867

Table of Contents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

includes information for the pension plans with accumulated benefit obligations in excess of pension plan assets:



	December 31,
(in millions)	2017		2016
Accumulated Benefit Obligation	$	237	$	384
Fair Value of Plan Assets	206		354

Beginning in 2016, the Company elected to measure service and interest costs by applying the specific spot rates along the yield curve to the plans' liability cash flows. Prior to 2016, the Company measured service and interest costs for pension and other postretirement benefits utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. TEP believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans' liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of its plan obligations nor the funded status. TEP accounted for this change as a change in accounting estimate, and accordingly, accounted for it on a prospective basis. Net periodic benefit plan cost includes the following components:


	Pension Benefits									Other Retiree Benefits								Pension Benefits									Other Postretirement Benefits
	Year Ended December 31,																	Years Ended December 31,
	2014			2013			2012			2014			2013			2012
	Millions of Dollars
(in millions)																		2017			2016			2015			2017			2016			2015
Service Cost	$	10		$	11		$	9		$	4		$	3		$	3	$	13		$	12		$	12		$	4		$	4		$	4
Interest Cost	16			14			15			3			3			3		15			15			17			2			2			3
Expected Return on Plan Assets	(21		)	(19		)	(17		)	(1		)	(1		)	—		(25		)	(23		)	(23		)	(1		)	(1		)	(1		)
Actuarial Loss Amortization	3			8			7			—			—			—
Amortization of Net Loss																		8			7			7			—			—			—
Net Periodic Benefit Cost	$	8		$	14		$	14		$	6		$	5		$	6	$	11		$	11		$	13		$	5		$	5		$	6



Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specifiedin its charter)
Arizona (State or other jurisdiction of incorporation or organization)		86-0062700 (I.R.S. Employer Identification No.)
88 East Broadway Boulevard, Tucson, AZ 85701 (Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: (520) 571-4000



Large Accelerated Filero	¨	Accelerated Filero	¨ Non-Accelerated Filerx	~~Non-accelerated Filer~~	x	Smaller Reporting Companyo	¨ Emerging Growth Companyo
		(do not check if a smaller reporting company)



Definitions	v
Forward-Looking Information	vii
PART I

Item 1. Business	1
Overview of Business	1
Environmental Matters	108
Employees	128
Executive Officers of the Registrant	139
SEC Reports Available on TEP's Website	149
Item 1A. Risk Factors	1410
Item 1B. Unresolved Staff Comments	1813
Item 2. Properties	1814
Item 3. Legal Proceedings	2015
Item 4. Mine Safety Disclosures	2015

PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	2116
Item 6. Selected Financial Data	2116
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	2217
Critical Accounting Policies	3731
Recently Issued Accounting Pronouncements	4135
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	4135
Item 8. Consolidated Financial Statements and Supplementary Data	45
~~Management's Report on Internal Controls Over Financial Reporting~~	4538
Reports of Independent Registered Public Accounting Firm	4638
Consolidated Statements of Income	4840
Consolidated Statements of Comprehensive Income	4941
Consolidated Statements of Cash Flows	5042
Consolidated Balance Sheets	5143
Consolidated Statements ~~of Capitalization~~	53
~~Consolidated Statement~~ of Changes in Stockholder's Equity	5445
Notes to Consolidated Financial Statements	46
Note 1. Nature of Operations and ~~Financial Statement Presentation~~Summary of Significant Accounting Policies	5546
Note 2. Regulatory Matters	6152
Note 3. Utility Plant and Jointly-Owned Facilities	6456
Note 4. ~~Related Party Transactions~~Accounts Receivable	6758
Note 5. Related Party Transactions	59
Note 6. Debt, Credit ~~Facilities,~~Facility, and Capital Lease Obligations	68
~~Note 6. Commitments, Contingencies, and Environmental Matters~~	7160
Note 7. ~~Purchase of Gas-Fired Generation Facility~~Commitments and Contingencies	7663
Note 8. Employee Benefit Plans	7766
Note 9. Share-Based Compensation	72
Note 10. Supplemental Cash Flow Information	8473
Note ~~10.~~11. Fair Value Measurements and Derivative Instruments	85
~~Note 11. Income Taxes~~	9073
Note 12. Income Taxes	78
Note 13. Recently Issued Accounting Pronouncements	9280
Note ~~13.~~14. Quarterly Financial Data (Unaudited)	93
~~Schedule II - Valuation and Qualifying Accounts~~	9381
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	9382
Item 9A. Controls and Procedures	9382




Item 10. Directors, Executive Officers, and Corporate Governance	9583
Item 11. Executive Compensation	9983
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~120~~83
Item 13. Certain Relationships and Related Transactions and Director Independence	~~121~~83
Item 14. Principal Accounting Fees and Services	~~122~~83

PART IV

Item 15. Exhibits, Financial Statement Schedules	~~124~~85
Item 16. Form 10-K Summary	85
Exhibits	86
Signatures	~~125~~
~~Exhibit Index~~	~~126~~89



Springerville		~~Springerville Generating Station~~
~~Springerville Coal Handling Facilities~~		~~Coal handling facilities at Springerville used by all four Springerville units~~
~~Springerville Coal Handling Facilities Leases~~		~~Leases for coal handling facilities at Springerville used in common by all four Springerville units~~
~~Springerville Common Facilities~~		~~Facilities at Springerville used in common by all four Springerville units~~
~~Springerville Common Facilities Leases~~		~~Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities~~
~~Springerville Unit 1~~		~~Unit 1 of the Springerville Generating Station~~
~~Springerville Unit 1 Leases~~		~~Leveraged lease arrangement relating to Springerville Unit 1 and an~~ ~~undivided one-half interest in certain Springerville Common Facilities~~
~~Springerville Unit 2~~		~~Unit 2 of the Springerville Generating Station~~
~~Springerville Unit 3~~		~~Unit 3 of the Springerville Generating Station~~
~~Springerville Unit 4~~		~~Unit 4 of the~~ Springerville Generating Station
SRP		Salt River Project Agricultural Improvement and Power District
Sundt		H. Wilson Sundt Generating Station
~~Sundt Unit 4~~TCJA		~~Unit 4 of~~On December 22, 2017, the ~~H. Wilson Sundt Generating Station~~Tax Cuts and Jobs Act was signed into law enacting significant changes to the Internal Revenue Code including a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017
TEP		Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Third-Party Owners		Wilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of ~~the remaining two owner participants,~~ Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners)
TSA		Transmission Service Agreement
Tri-State		Tri-State Generation and Transmission Association, Inc.
UES		UniSource Energy Services, Inc., a wholly-owned subsidiary of UNS Energy Corporation, and the intermediate holding company established to own the operating companies UNS Electric, Inc. and UNS Gas, Inc.
UNS Electric		UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
UNS Energy		UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy ~~affiliates~~Affiliates		Affiliated subsidiaries of UNS Energy Corporation including UniSource Energy Services Inc., UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc.
UNS Gas		UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy



~~2010 Credit Agreement~~		~~The 2010 Credit Agreement consists of a $200 million revolving credit and LOC facility together with an $82 million LOC facility to support tax-exempt bonds~~
2010 Reimbursement Agreement		Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
~~2013 Covenants Agreement~~		~~A Lender Rate Mode Covenants Agreement between TEP and the purchaser of $100 million of unsecured tax-exempt bonds that were issued on behalf of TEP in November 2013 and sold in a private placement~~
~~2013 TEP~~2017 Rate Order		A rate order issued by the ACC resulting in a new rate structure for TEP, effective ~~July 1, 2013~~
~~2014 Credit Agreement~~		~~The 2014 Credit Agreement consists of a $130 million term loan commitment and a $70 million revolving credit commitment~~on February 27, 2017
ACC		Arizona Corporation Commission
APS		Arizona Public Service Company
BART		Best Available Retrofit Technology
~~Base O&M~~BBtu		~~A non-GAAP financial measure that represents the fundamental level of operating and maintenance expense related to our business~~
~~Base Rates~~		The portion of TEP’s Retail Rates attributed to generation, transmission, distribution, and customer costs. Base Rates exclude authorized charges designed to recover specific costs that are passed through to customers including fuel and purchased energy costs, energy efficiency program costs, certain environmental compliance costs, and a portion of renewable energy costs
~~Btu~~		Billion British thermal unit(s)
~~Cooling Degree Days~~		~~An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures~~
DG		Distributed Generation
DSM		Demand Side Management
~~ECA~~		~~Environmental Compliance Adjustor~~
EE Standards		Energy Efficiency Standards
EPA		Environmental Protection Agency
EPNG		El Paso Natural Gas Company, LLC.
FERC		Federal Energy Regulatory Commission
Fortis		Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
Four Corners		Four Corners Generating Station
GAAP		Generally Accepted Accounting Principles in the United States of America
~~GBtu~~Gila River		~~Billion British thermal units~~Gila River Generating Station
GWh		Gigawatt-hour(s)
~~Gila River Unit 3~~		~~Unit 3 of the Gila River Generating Station~~
~~Heating Degree Days~~		~~An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65~~
kV		Kilo-volt(s)
kWh		Kilowatt-hour(s)
LFCR		Lost Fixed Cost Recovery Mechanism
LOC		~~Letter~~Letter(s) of Credit
~~Merger~~Luna		~~The acquisition of UNS Energy in 2014 pursuant to the Agreement and Plan of Merger between UNS Energy and FortisUS Inc.~~Luna Generating Station
MMBtu		Million British thermal units
MW		Megawatt(s)
MWh		Megawatt-hour(s)
Navajo		Navajo Generating Station
NBV		Net Book Value
PNM		Public Service Company of New Mexico



PPA		Power Purchase Agreement
PPFAC		Purchased Power and Fuel Adjustment Clause
~~ppb~~PV		~~Parts per billion~~Photovoltaic
REC		Renewable Energy Credit
Regional Haze Rules		Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
RES		Renewable Energy Standard
Retail Rates		Rates designed to allow a regulated utility recovery of its cost of providing services and an opportunity to ~~recover its reasonable operating and capital costs and~~ earn a reasonable return on its ~~utility plant in service~~investment
RICE		Reciprocating Internal Combustion Engine
San Juan		San Juan Generating Station
SCR		Selective Catalytic Reduction
SES		Southwest Energy Solutions, Inc.
SJCC		San Juan Coal Company
SNCR		Selective Non-Catalytic Reduction



(sales in GWh)	2017			2016			2015
Electric Sales
Residential	3,786	28	%	3,724	29	%	3,724		28	%
Commercial	2,192	17	%	2,139	17	%	2,124		15	%
Industrial, non-Mining	1,939	15	%	2,006	16	%	2,063		15	%
Industrial, Mining	991	8	%	997	8	%	1,109		8	%
Other	18	—	%	30	—	%	33		—	%
Total Retail Sales by Customer Class	8,926	68	%	8,896	70	%	9,053		66	%
Wholesale Sales, Long-Term	587	4	%	463	4	%	750		5	%
Wholesale Sales, Short-Term	3,630	28	%	3,308	26	%	3,928		29	%
Total Electric Sales	13,143	100	%	12,667	100	%	13,731		100	%

Average Number of Retail Customers
Residential	381,399	90	%	378,991	90	%	376,439	��	90	%
Commercial	38,564	9	%	38,403	9	%	38,253		9	%
Industrial, non-Mining	520	—	%	580	—	%	588		—	%
Industrial, Mining	4	—	%	4	—	%	4		—	%
Other	1,879	1	%	1,866	1	%	1,857		1	%
Total Retail Customers	422,366	100	%	419,844	100	%	417,141		100	%



		Contracts Expire
Counterparty		December 31,
Navajo Tribal Utility Authority		2022
TRICO Electric Cooperative		2024
Navopache Electric Cooperative		2041



	Unit		Date	Resource	Capacity	Operating	TEP’s Share
Generating Source	No.	Location	In Service	Type	MW	Agent	%	MW
Springerville Station⁽¹⁾	1	Springerville, AZ	1985	Coal	387	TEP	49.5	192
Springerville Station	2	Springerville, AZ	1990	Coal	390	TEP	100.0	390
San Juan Station	1	Farmington, NM	1976	Coal	340	PNM	50.0	170
San Juan Station	2	Farmington, NM	1973	Coal	340	PNM	50.0	170
Navajo Station	1	Page, AZ	1974	Coal	750	SRP	7.5	56
Navajo Station	2	Page, AZ	1975	Coal	750	SRP	7.5	56
Navajo Station	3	Page, AZ	1976	Coal	750	SRP	7.5	56
Four Corners Station	4	Farmington, NM	1969	Coal	785	APS	7.0	55
Four Corners Station	5	Farmington, NM	1970	Coal	785	APS	7.0	55
Gila River Power Station	3	Gila Bend, AZ	2003	Gas	550	Ethos Energy	75.0	413
Luna Generating Station	1	Deming, NM	2006	Gas	555	PNM	33.3	185
Sundt Station	1	Tucson, AZ	1958	Gas/Oil	81	TEP	100.0	81
Sundt Station	2	Tucson, AZ	1960	Gas/Oil	81	TEP	100.0	81
Sundt Station	3	Tucson, AZ	1962	Gas/Oil	104	TEP	100.0	104
Sundt Station ⁽²⁾	4	Tucson, AZ	1967	Coal	120	TEP	100.0	120
Sundt Internal Combustion Turbines		Tucson, AZ	1972-1973	Gas/Oil	50	TEP	100.0	50
DeMoss Petrie		Tucson, AZ	2001	Gas	75	TEP	100.0	75
North Loop		Tucson, AZ	2001	Gas	94	TEP	100.0	94
Springerville Solar Station		Springerville, AZ	2002-2014	Solar	16	TEP	100.0	16
Tucson Solar Projects		Tucson, AZ	2010-2014	Solar	12	TEP	100.0	12
Ft. Huachuca Project		Ft. Huachuca, AZ	2014	Solar	17	TEP	100.0	17
Total TEP Capacity ⁽³⁾								2,448


⁽²⁾	~~Sundt Station Unit 4 can be operated on either coal or natural gas. The table above reflects~~TEP, along with the ~~nominal generating capacity assuming~~other participants at the ~~unit is fueled~~Navajo Generating Facility (Navajo), plan to discontinue operations of Navajo Units 1-3 by ~~coal. If~~ the ~~Unit burns natural gas, it has a nominal capacity~~end of ~~156 MW.~~2019.


⁽³⁾	~~Excludes 932 MW~~TEP plans to discontinue operations of ~~additional resources, which consist~~Sundt Units 1 & 2 by the end of ~~certain~~2020.


⁽⁴⁾	On December 20, 2017, San Juan Generating Station (San Juan) Unit 2 was removed from service. TEP's 50% share of San Juan Unit 2's nominal capacity ~~purchases and interruptible retail load.~~was 170 MW.



Peak Demand	2014		2013		2012		2011		2010
	MW
Retail Customers	2,218		2,230		2,290		2,334		2,333
Firm Sales to Other Utilities	673		484		286		322		340
Coincident Peak Demand (A)	2,891		2,714		2,576		2,656		2,673
Total Generating Resources	2,240		2,240		2,267		2,262		2,245
Other Resources ⁽¹⁾	932		775		683		1,009		799
Total TEP Resources (B)	3,172		3,015		2,950		3,271		3,044
Total Margin (B) – (A)	281		301		374		615		371
Reserve Margin (% of Coincident Peak Demand)	10	%	11	%	15	%	23	%	14	%



(in MW)	2017	2016	2015	2014	2013
Retail Customers	2,415	2,278	2,222	2,218	2,230



~~Yes~~ ¨		No x



~~Yes~~ ¨		No x



~~Yes~~ x		No ¨



Yes x No ox		No ¨


⁽¹⁾	~~Other Resources include firm power purchases and interruptible~~ In 2017, TEP's generation and purchased resources were sufficient to meet total retail and long-term wholesale ~~loads.~~


	Average Cost per kWh (cents per kWh)			Percentage of Total kWh Resources						Average Cost (cents per kWh)			Percentage of Total kWh Resources
	2014	2013	2012	2014		2013		2012		2017	2016	2015	2017		2016		2015
Coal	2.50	2.66	2.54	68	%	75	%	72	%	2.41	2.30	2.44	54	%	62	%	60	%
Gas	4.99	4.57	4.54	9	%	8	%	11	%	3.06	2.84	3.35	23	%	25	%	19	%
Purchased Power	4.79	4.83	3.44	23	%	17	%	17	%
All Sources	3.64	3.54	3.19	100	%	100	%	100	%
Purchased Power, Non-Renewable										3.78	3.43	3.04	18	%	8	%	18	%
Purchased Power, Renewable										6.67	7.00	9.82	5	%	5	%	3	%
													100	%	100	%	100	%


Station	Coal Supplier	2014 Coal Consumption (tons in 000s)	Contract Expiration	Avg. Sulfur Content	Coal Obtained From	Coal Supplier	2017 Coal Consumption (tons in 000s)	Contract Expiration	Average Sulfur Content	Coal Obtained From
Springerville	Peabody CoalSales	2,868	2020	0.9%	Lee Ranch Coal Co.	Peabody CoalSales	2,289	2020	1.0%	Lee Ranch Mine/El Segundo Mine
Four Corners⁽¹⁾	BHP Billiton	344	2031	0.7%	Navajo Indian Tribe	NTEC	285	2031	0.7%	Navajo Mine
San Juan(1)	San Juan Coal Co.	1,146	2017	0.8%	Federal and State Agencies	San Juan Coal Co.	1,181	2022	0.8%	San Juan Mine
Navajo	Peabody CoalSales	591	2019	0.6%	Navajo and Hopi Indian Tribes	Peabody CoalSales	441	2019	0.6%	Kayenta Mine


⁽¹⁾	~~Beginning in July 2016 through June 2031,~~Reflects the ~~coal for Four Corners will be purchased~~fuel consumption of San Juan Units 1 and 2. In December 2017, San Juan Unit 2 was removed from ~~the Navajo Transitional Energy Company (NTEC). NTEC purchased the mine located near Four Corners from BHP Billiton and will begin operating the mine in 2016.~~service.



TEP’S UTILITY OPERATING STATISTICS
	2014		2013		2012		2011		2010
Generation and Purchased Power – kWh (000)
Remote Generation	9,616,347		10,586,972		10,284,612		10,005,127		9,077,032
Local Tucson Generation	864,949		674,443		803,146		906,496		1,492,885
Renewable Generation	48,434		38,206		44,930		28,049		24,511
Purchased Power	3,195,173		2,328,581		2,328,420		2,686,918		2,846,005
Total Generation and Purchased Power	13,724,903		13,628,202		13,461,108		13,626,590		13,440,433
Less Losses and Company Use	859,638		885,026		789,613		822,220		879,423
Total Energy Sold	12,865,265		12,743,176		12,671,495		12,804,370		12,561,010
Sales – kWh (000)
Residential	3,726,982		3,866,665		3,820,637		3,888,011		3,869,540
Commercial	2,169,897		2,187,095		2,187,617		2,184,241		2,171,694
Industrial	2,098,229		2,113,659		2,132,214		2,145,163		2,138,749
Mining	1,137,188		1,079,150		1,092,518		1,083,071		1,079,327
Other	33,057		32,350		31,833		31,621		32,478
Total – Electric Retail Sales	9,165,353		9,278,919		9,264,819		9,332,107		9,291,788
Electric Wholesale Sales- Long-Term	617,502		605,426		657,740		902,139		987,957
Electric Wholesale Sales- Short-Term	3,082,410		2,858,831		2,748,936		2,570,124		2,281,265
Total Electric Sales	12,865,265		12,743,176		12,671,495		12,804,370		12,561,010
Operating Revenues ($000)
Residential	$	409,964	$	400,999	$	387,840	$	383,908	$	372,212
Commercial	261,813		252,547		247,157		241,044		233,567
Industrial	170,436		164,433		166,739		164,024		159,937
Mining	70,110		65,094		66,158		65,720		62,112
Other	2,985		2,809		2,693		2,601		2,593
RES, DSM, ECA and LFCR	54,837		48,475		45,292		46,633		37,767
Total – Electric Retail Sales	970,145		934,357		915,879		903,930		868,188
Wholesale Revenue- Long-Term	28,216		26,203		24,910		41,056		55,653
Wholesale Revenue- Short-Term	113,575		91,467		71,257		72,798		71,435
California Power Exchange Provision for Wholesale Refunds	—		—		—		—		(2,970		)
Transmission	16,532		14,830		15,793		16,392		20,863
Other Revenues	141,433		129,833		133,821		122,210		112,098
Total Operating Revenues	$	1,269,901	$	1,196,690	$	1,161,660	$	1,156,386	$	1,125,267
Customers (End of Period)
Residential	374,204		372,411		369,480		367,396		366,217
Commercial	38,079		37,913		37,672		37,536		37,215
Industrial	604		617		632		636		635
Mining	4		4		4		4		4
Other	1,858		1,857		1,833		1,814		1,829
Total Retail Customers	414,749		412,802		409,621		407,386		405,900
Average Retail Revenue per kWh Sold (cents)
Residential	11.0		10.4		10.2		9.9		9.6
Commercial	12.1		11.5		11.3		11.0		10.8
Industrial and Mining	7.4		7.2		7.2		7.1		6.9
Average Retail Revenue per kWh Sold (cents) (excludes RES, DSM, ECA and LFCR)	10.0		9.5		9.4		9.2		8.9
Average Revenue per Residential Customer	$	1,096	$	1,077	$	1,050	$	1,045	$	1,016
Average kWh Sales per Residential Customer	9,960		10,383		10,341		10,583		10,566



Name	Age	Position(s) Held	Executive Officer Since
David G. Hutchens	48	President and Chief Executive Officer	2007
Kevin P. Larson	58	Senior Vice President and Chief Financial Officer	1997
Philip J. Dion	46	Senior Vice President, Public Policy and Customer Solutions	2008
Kentton C. Grant	56	Vice President and Treasurer	2007
Todd C. Hixon	48	Vice President and General Counsel	2011
Karen G. Kissinger	60	Vice President and Chief Compliance Officer	1991
Mark C. Mansfield	59	Vice President, Energy Resources	2012
Frank P. Marino	50	Vice President and Controller	2013
Thomas A. McKenna	66	Vice President, Energy Delivery	2007
Catherine E. Ries	55	Vice President, Human Resources and Information Technology	2007
Herlinda H. Kennedy	53	Corporate Secretary	2006



Name	Age	Position(s) Held	Executive Officer Since
David G. Hutchens ⁽¹⁾	51	President and Chief Executive Officer	2007
Frank P. Marino ⁽¹⁾	53	Vice President and Chief Financial Officer	2013
Erik B. Bakken	45	Vice President, Transmission and Distribution Planning and Environmental	2018
Kentton C. Grant	59	Vice President, Rates and Planning	2007
Susan M. Gray	45	Vice President, Energy Delivery	2015
Todd C. Hixon ⁽¹⁾	51	Vice President, General Counsel and Chief Compliance Officer	2011
Mark C. Mansfield	62	Vice President, Energy Resources	2012
Catherine E. Ries	58	Vice President, Customer and Human Resources	2007
Mary Jo Smith	60	Vice President, Public Policy and Rates	2015
Morgan C. Stoll	47	Vice President and Chief Information Officer	2016
Martha B. Pritz	56	Treasurer	2017
Herlinda H. Kennedy	56	Corporate Secretary	2006



~~David G. Hutchens~~ ⁽¹⁾	~~Mr. Hutchens has served as Chief Executive Officer~~Member of the TEP Board of Directors. The directors of TEP ~~since 2014; President of TEP since 2011; Executive Vice President of TEP in 2011; Vice President of TEP from 2007-2011. Mr. Hutchens joined TEP in 1995.~~
~~Kevin P. Larson~~	Mr. Larson has served as Senior Vice President and Chief Financial Officer of TEP since September 2005. Mr. Larson joined TEP in 1985 and thereafter held various positions in its finance department and investment subsidiaries. He wasare elected ~~Vice President in March 1997. In October 2000, he was elected Vice President and Chief Financial Officer.~~
~~Philip J. Dion~~	Mr. Dion has served as Senior Vice President, Public Policy and Customer Solutions of TEP since August 2013. Mr. Dion was named Vice President, Public Policy in April 2010. Mr. Dion joined TEP in February 2008 as Vice President of Legal and Environmental Services.
~~Kentton C. Grant~~	~~Mr. Grant was elected Treasurer in 2010 and has served as Vice President of TEP since January 2007. Mr. Grant joined TEP in 1995.~~
~~Todd C. Hixon~~	Mr. Hixon has served as Vice President and General Counsel of TEP since May 2011. Mr. Hixon joined TEP’s legal department in 1998 and served in a variety of capacities, most recently serving as Associate General Counsel.
~~Karen G. Kissinger~~	Ms. Kissinger has served as Vice President and Chief Compliance Officer of TEP since August 2013. Ms. Kissinger served as Vice President, Controller, and Chief Compliance Officer from 2001 to 2013. Ms. Kissinger joined TEP as Vice President and Controller in January 1991.
~~Mark C. Mansfield~~	~~Mr. Mansfield has served as Vice President,~~annually by TEP's sole shareholder, UNS Energy, ~~Resources since 2012. He joined the company in 2008, most recently serving as Senior Director of Generation.~~
~~Frank P. Marino~~	~~Mr. Marino has served as Vice President and Controller of TEP since August 2013. Mr. Marino joined TEP as Assistant Controller in January 2013. Prior to joining TEP, he served various roles~~acting at the AES Corporation, a global power company. In 2012 he served as AES' Vice President for Business Demand and Outsourcing Management, and from 2007-2011 he served as Chief Financial Officer for two different business units.
~~Thomas A. McKenna~~	~~Mr. McKenna has served as Vice President, Energy Delivery since August 2013. Mr. McKenna was named Vice President, Engineering in January 2007. Mr. McKenna joined an affiliate~~direction of ~~TEP in 1998.~~
~~Catherine E. Ries~~	~~Ms. Ries has served as Vice President, Human Resources and Information Technology, since May 2011. Ms. Ries joined TEP as Vice President~~the Board of ~~Human Resources in June 2007.~~
~~Herlinda H. Kennedy~~	~~Ms. Kennedy has served as Corporate Secretary~~Directors of ~~TEP since September 2006. Ms. Kennedy joined TEP in 1980 and was named assistant Corporate Secretary in 1999.~~UNS Energy.



(in thousands)	2017		2016		2015		2014		2013
Income Statement Data
Operating Revenues	$	1,340,935	$	1,234,995	$	1,306,544	$	1,269,901	$	1,196,690
Net Income	176,668		124,438		127,794		102,338		101,342
Balance Sheet Data
Total Utility Plant, Net	$	3,768,702	$	3,782,806	$	3,558,229	$	3,425,190	$	2,944,455
Total Assets	4,590,249		4,449,989		4,249,478		4,119,830		3,482,860
Long-Term Debt, Net	1,354,423		1,453,072		1,451,720		1,361,828		1,213,367
Non-Current Capital Lease Obligations	28,519		39,267		55,324		69,438		131,370
Other Data
Ratio of Earnings to Fixed Charges ⁽¹⁾	5.06		3.69		3.74		2.56		2.67



	Year Ended				Increase (Decrease)		Year Ended		Increase (Decrease)
	2014		2013		Percent⁽¹⁾		2012		Percent⁽¹⁾
Energy Sales, kWh (in Millions):
Electric Retail Sales:
Residential	3,727		3,867		(3.6	)%	3,821		1.2	%
Commercial	2,170		2,187		(0.8	)%	2,187		—	%
Industrial	2,098		2,114		(0.8	)%	2,132		(0.9	)%
Mining	1,137		1,079		5.4	%	1,093		(1.2	)%
Public Authorities	33		32		3.1	%	32		1.6	%
Total Electric Retail Sales	9,165		9,279		(1.2	)%	9,265		0.2	%
Retail Margin Revenues (in Millions):
Residential	$	280	$	271	3.3	%	$	248	9.3	%
Commercial	188		181		3.9	%	171		5.9	%
Industrial	104		97		7.2	%	93		5.4	%
Mining	38		34		11.8	%	30		11.5	%
Public Authorities	2		2		—	%	2		5.9	%
Total by Customer Class	612		585		4.6	%	544		7.7	%
LFCR Revenues	11		2		450.0	%	—		NM
Total Retail Margin Revenues (Non-GAAP)⁽²⁾	623		587		6.1	%	544		7.9	%
Fuel and Purchased Power Revenues	303		300		1.0	%	327		(8.1	)%
RES, DSM and ECA Revenues	44		47		(6.4	)%	45		4.4	%
Total Retail Revenues (GAAP)	$	970	$	934	3.9	%	$	916	2.0	%
Average Retail Margin Rate (Cents / kWh):⁽¹⁾
Residential	7.51		7.02		7.0	%	6.50		8.0	%
Commercial	8.66		8.28		4.6	%	7.82		5.9	%
Industrial	4.96		4.61		7.6	%	4.33		6.5	%
Mining	3.34		3.14		6.4	%	2.78		12.9	%
Public Authorities	6.06		5.56		9.0	%	5.34		4.1	%
Total Average Retail Margin Rate Excluding LFCR	6.68		6.30		6.0	%	5.87		7.3	%
Average LFCR Rate	0.12		0.02		500.0	%	—		NM
Total Average Retail Margin Rate Including LFCR	6.80		6.31		7.8	%	5.87		7.5	%
Average Fuel and Purchased Power Revenues	3.31		3.24		2.2	%	3.52		(8.0	)%
Average RES, DSM and ECA Revenues	0.48		0.52		(7.7	)%	0.49		6.1	%
Total Average Retail Revenues	10.59		10.07		5.2	%	9.88		1.9	%

Weather Data:
Cooling Degree Days
Year Ended December 31,	1,557		1,631		(4.5	)%	1,556		4.8	%
10-Year Average	1,515		1,491		NM		1,484		NM
Heating Degree Days
Year Ended December 31,	930		1,449		(35.8	)%	1,201		20.6	%
10-Year Average	1,335		1,404		NM		1,394		NM



	Years Ended December 31,				Increase (Decrease)		Year Ended December 31		Increase (Decrease)
($ in millions)	2017		2016		Percent		2015		Percent
Retail Revenues (GAAP)	$	1,041	$	990	5.2	%	$	1,022	(3.1	)%
Less recoveries from:
Fuel and Purchased Power	275		305		(9.8	)%	344		(11.3	)%
DSM and RES Surcharge	53		54		(1.9	)%	49		10.2	%
Retail Margin Revenues (non-GAAP) ⁽¹⁾	$	713	$	631	13.0	%	$	629	0.3	%

Electric Sales (kWh in millions)
Residential	3,786		3,724		1.7	%	3,724		—	%
Commercial	2,192		2,139		2.5	%	2,124		0.7	%
Industrial	1,939		2,006		(3.3	)%	2,063		(2.8	)%
Mining	991		997		(0.6	)%	1,109		(10.1	)%
Public Authorities	18		30		(40.0	)%	33		(9.1	)%
Total Retail Sales	8,926		8,896		0.3	%	9,053		(1.7	)%
Wholesale Sales, Long-Term	587		463		26.8	%	750		(38.3	)%
Wholesale Sales, Short-Term	3,630		3,308		9.7	%	3,928		(15.8	)%
Total Electric Sales	13,143		12,667		3.8	%	13,731		(7.7	)%

Average Retail Rate (cents / kWh)	11.66		11.13		4.8	%	11.29		(1.4	)%
Average Fuel and Purchased Power Rate	3.08		3.43		(10.2	)%	3.80		(9.7	)%
Average DSM and RES Surcharge Rate	0.59		0.61		(3.3	)%	0.54		13.0	%
Total Average Retail Margin Rate	7.99		7.09		12.7	%	6.95		2.0	%


⁽¹⁾	~~Calculated on un-rounded data and may not correspond exactly to data shown in table.~~


⁽¹⁾	~~Represents revenues and reimbursements from Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, to TEP related to the operation of these plants.~~



	Generation and Purchased Power						Fuel and Purchased Power Expense
	2014		2013		2012		2014			2013			2012
	Millions of kWh						Millions of Dollars
Coal-Fired Generation	9,271		10,254		9,702		$	232		$	273		$	247
Gas-Fired Generation	1,210		1,007		1,435		60			46			65
Utility Owned Renewable Generation	48		38		45		—			—			—
Reimbursed Fuel Expense for Springerville Units 3 and 4	—		—		—		5			7			7
Total Generation	10,529		11,299		11,182		298			326			319
Total Purchased Power	3,195		2,329		2,328		153			112			80
Transmission and Other PPFAC Recoverable Costs	—		—		—		18			12			6
Increase (Decrease) to Reflect PPFAC Recovery Treatment	—		—		—		(11		)	(12		)	31
Subtotal	13,724		13,628		13,510		$	457		$	438		$	436
Less Line Losses and Company Use	(859	)	(885	)	(839	)
Total Energy Sold	12,865		12,743		12,671


⁽²⁾	~~These expenses are being collected from customers and the corresponding amounts are recorded in retail revenue.~~



	As of December 31, 2014
	Millions of Dollars
Cash and Cash Equivalents	$	74
Borrowings under Revolving Credit Facilities⁽¹⁾	85
Amount Available under Revolving Credit Facilities	185


⁽¹⁾	~~Includes an LOC issued under the 2010 Credit Agreement.~~



(in millions)	December 31, 2017
Cash and Cash Equivalents	$	38
Amount Available under Revolving Credit Facility ⁽¹⁾	215
Total Liquidity	$	253


⁽¹⁾	TEP's revolving credit facility provides for $250 million of revolving credit commitments and a Letter of Credit (LOC) sublimit of $50 million. TEP requested and was granted two one-year extensions. The new maturity date is October 2022.



	Years Ended						Increase (Decrease)		Year Ended			Increase (Decrease)
(in millions)	2017			2016			Percent		2015			Percent
Operating Activities	$	448		$	425		5.4	%	$	365		16.4	%
Investing Activities	(392		)	(373		)	5.1	%	(501		)	(25.5	)%
Financing Activities	(50		)	(69		)	(27.5	)%	120			*
Net Increase (Decrease)	6			(17		)	*		(16		)	6.3	%
Beginning of Period	43			60			(28.3	)%	76			(21.1	)%
End of Period ⁽¹⁾	$	49		$	43		14.0	%	$	60		(28.3	)%