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EXCEL - IDEA: XBRL DOCUMENT - TUCSON ELECTRIC POWER COFinancial_Report.xls
EX-32 - EXHIBIT 32 - TUCSON ELECTRIC POWER COtepex323312015.htm
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EX-31.B - EXHIBIT 31B - TUCSON ELECTRIC POWER COtepex31b3312015.htm
EX-31.A - EXHIBIT 31A - TUCSON ELECTRIC POWER COtepex31a3312015.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2015
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                     . 
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specified in 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
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes  x
 
No   ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes  x
 
No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer
¨
Accelerated Filer
¨
Non-accelerated Filer
x
Smaller Reporting Company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes  ¨
 
No  x
As of May 4, 2015, Tucson Electric Power Company had 32,139,434 shares of common stock, no par value, outstanding, all of which were held by UNS Energy Corporation.




Table of Contents
PART I
 
 
 
 
 
 
 
PART II
 
 
 

ii




DEFINITIONS
The abbreviations and acronyms used in the first quarter 2015 Form 10-Q are defined below:
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 TEP Reimbursement Agreement
 
Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2013 TEP 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 $70 million revolving credit commitment; a $130 million term loan commitment portion was terminated upon repayment per the agreement
ACC
 
Arizona Corporation Commission
APS
 
Arizona Public Service Company
BART
 
Best Available Retrofit Technology
Base O&M
 
A non-GAAP financial measure that represents the fundamental level of operating and maintenance expense related to our business
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
 
Energy Efficiency
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
GBtu
 
Billion British thermal units
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
kWh
 
Kilowatt-hour(s)
LFCR
 
Lost Fixed Cost Recovery
LOC
 
Letter of Credit
MMBtu
 
Million British thermal units
MW
 
Megawatt(s)
MWh
 
Megawatt-hour(s)
Navajo
 
Navajo Generating Station
PNM
 
Public Service Company of New Mexico
ppb
 
Parts per billion
PPFAC
 
Purchased Power and Fuel Adjustment Clause
Regional Haze Rules
 
Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
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
Springerville
 
Springerville Generating Station

iii




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
 
Unit 4 of the H. Wilson Sundt Generating Station
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)
Tri-State
 
Tri-State Generation and Transmission Association, Inc.
UNS Electric
 
UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy
UNS Energy
 
UNS Energy Corporation
UNS Energy affiliates
 
Affiliated subsidiaries of UNS Energy including UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc.
UNS Gas
 
UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy
 


iv



FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Tucson Electric Power (TEP) is including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or for TEP in this Quarterly Report on Form 10-Q. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as anticipates, estimates, expects, intends, plans, predicts, projects, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, TEP disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report, except as otherwise may be required by the federal securities laws.
Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed therein. We express our expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in: Part II, Item 1A. Risk Factors; Part I, Item 2. Management’s Discussion and Analysis; and other parts of this report. These factors include: state and federal regulatory and legislative decisions and actions; changes in, and compliance with, environmental laws, regulations, decisions and policies that could increase operating and capital costs, reduce generating facility output or accelerate generating facility retirements; regional economic and market conditions which could affect customer growth and energy usage; changes in energy consumption by retail customers; weather variations affecting energy usage; the cost of debt and equity capital and access to capital markets; the performance of the stock market and changing interest rate environment, which affect the value of our pension and other retiree benefit plan assets and the related contribution requirements and expense; the inability to make additions to our existing high voltage transmission system; unexpected increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting estimates; the ongoing impact of mandated energy efficiency and distributed generation initiatives; changes to long-term contracts; the cost of fuel and power supplies; ability to obtain coal from our suppliers; cyber attacks or challenges to our information security; and the performance of TEP's generating plants.


v



PART I
ITEM 1. FINANCIAL STATEMENTS
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
 
 
March 31,
 
December 31,
 
 
2015
 
2014
 
 
(Unaudited)
 
 
Thousands of Dollars
ASSETS
 
 
 
 
Utility Plant
 
 
 
 
Plant in Service
 
$
5,225,923

 
$
5,175,148

Utility Plant Under Capital Leases
 
436,199

 
667,157

Construction Work in Progress
 
173,889

 
109,070

Total Utility Plant
 
5,836,011

 
5,951,375

Less Accumulated Depreciation and Amortization
 
(2,091,266
)
 
(2,052,216
)
Less Accumulated Amortization of Capital Lease Assets
 
(286,693
)
 
(473,969
)
Total Utility Plant—Net
 
3,458,052

 
3,425,190


 
 
 
 
Investments and Other Property
 
38,428

 
37,599


 


 


Current Assets
 
 
 
 
Cash and Cash Equivalents
 
65,348

 
74,170

Accounts Receivable—Customer
 
72,702

 
80,713

Accounts Receivable—Other
 
15,498

 
12,808

Unbilled Accounts Receivable
 
32,069

 
36,804

Allowance for Doubtful Accounts-Customer
 
(4,776
)
 
(4,885
)
Allowance for Doubtful Accounts-Other
 
(5,521
)
 

Accounts Receivable—Due from Affiliates
 
4,617

 
5,382

Materials and Supplies
 
89,043

 
86,750

Deferred Income Taxes—Current
 
98,633

 
102,006

Fuel Inventory
 
33,758

 
36,368

Regulatory Assets—Current
 
79,380

 
69,383

Derivative Instruments
 
248

 
1,633

Other
 
25,557

 
22,848

Total Current Assets
 
506,556

 
523,980

Regulatory and Other Assets
 
 
 
 
Regulatory Assets—Noncurrent
 
238,018

 
223,192

Derivative Instruments
 
520

 
300

Other Assets
 
21,341

 
22,161

Total Regulatory and Other Assets
 
259,879

 
245,653

Total Assets
 
$
4,262,915

 
$
4,232,422

See Notes to Condensed Consolidated Financial Statements.
(Continued)

1



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
 
March 31,
 
December 31,
 
2015
 
2014
 
(Unaudited)
 
Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
 
 
 
Capitalization
 
 
 
Common Stock Equity
$
1,225,282

 
$
1,215,779

Capital Lease Obligations
59,958

 
69,438

Long-Term Debt
1,541,486

 
1,372,414

Total Capitalization
2,826,726

 
2,657,631

Current Liabilities
 
 
 
Current Obligations Under Capital Leases
131,428

 
173,822

Borrowings Under Revolving Credit Facilities

 
85,000

Accounts Payable—Trade
93,682

 
110,480

Accounts Payable—Due to Affiliates
4,200

 
2,933

Accrued Taxes Other than Income Taxes
47,482

 
36,110

Accrued Employee Expenses
20,766

 
15,679

Regulatory Liabilities—Current
33,308

 
38,847

Accrued Interest
16,190

 
21,021

Customer Deposits
20,047

 
20,339

Derivative Instruments
22,016

 
18,874

Other
11,168

 
9,673

Total Current Liabilities
400,287

 
532,778

Deferred Credits and Other Liabilities
 
 
 
Deferred Income Taxes—Noncurrent
492,662

 
491,546

Regulatory Liabilities—Noncurrent
313,062

 
321,186

Pension and Other Postretirement Benefits
138,585

 
138,319

Derivative Instruments
7,476

 
6,288

Other
84,117

 
84,674

Total Deferred Credits and Other Liabilities
1,035,902

 
1,042,013

Commitments, Contingencies & Environmental Matters (Note 5)

 

Total Capitalization and Other Liabilities
$
4,262,915

 
$
4,232,422

See Notes to Condensed Consolidated Financial Statements.
(Concluded)


2



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
Three Months Ended March 31,
 
2015
 
2014
 
(Unaudited)
 
Thousands of Dollars
Operating Revenues
 
 
 
Electric Retail Sales
$
201,622

 
$
186,015

Electric Wholesale Sales
41,462

 
42,084

Other Revenues
30,308

 
27,414

Total Operating Revenues
273,392

 
255,513

Operating Expenses
 
 
 
Fuel
70,569

 
67,630

Purchased Power
30,522

 
22,615

Transmission and Other PPFAC Recoverable Costs
4,707

 
3,909

Increase (Decrease) to Reflect PPFAC Recovery Treatment
3,249

 
(1,730
)
Total Fuel and Purchased Energy
109,047

 
92,424

Operations and Maintenance
82,645

 
81,345

Depreciation
34,733

 
30,811

Amortization
5,562

 
7,099

Taxes Other Than Income Taxes
13,212

 
11,835

Total Operating Expenses
245,199

 
223,514

Operating Income
28,193

 
31,999

Other Income (Deductions)
 
 
 
Interest Income
29

 
9

Other Income
622

 
1,912

Other Expense
(462
)
 
(2,115
)
Appreciation (Depreciation) in Fair Value of Investments
780

 
255

Total Other Income (Deductions)
969

 
61

Interest Expense
 
 
 
Long-Term Debt
14,410

 
14,240

Capital Leases
1,004

 
3,921

Other Interest Expense
434

 
313

Interest Capitalized
(454
)
 
(924
)
Total Interest Expense
15,394

 
17,550

Income Before Income Taxes
13,768

 
14,510

Income Tax Expense
4,339

 
5,338

Net Income
$
9,429

 
$
9,172

See Notes to Condensed Consolidated Financial Statements.


3




TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
Three Months Ended March 31,
 
2015
 
2014
 
(Unaudited)
 
Thousands of Dollars
Comprehensive Income
 
 
 
Net Income
$
9,429

 
$
9,172

Other Comprehensive Income (Loss)
 
 
 
Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit of $(12) and $(346)
14

 
481

Supplemental Executive Retirement Plan (SERP) Net Loss and Prior Service Cost Amortization, net of income tax (expense) benefit of $(37) and $(15)
60

 
24

Total Other Comprehensive Income (Loss), Net of Taxes
74

 
505

Total Comprehensive Income
$
9,503

 
$
9,677

See Notes to Condensed Consolidated Financial Statements.


4



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Three Months Ended March 31,
 
2015
 
2014
 
(Unaudited)
 
Thousands of Dollars
Net Income
$
9,429

 
$
9,172

Adjustments to Reconcile Net Income
 
 
 
       To Net Cash Flows from Operating Activities
 
 
 
Depreciation Expense
34,733

 
30,811

Amortization Expense
5,562

 
7,099

Amortization of Deferred Debt-Related Costs included in Interest Expense
716

 
635

Provision for Springerville Unit 1 - Third-Party Owners Unrealized Revenue
5,521

 

Use of Renewable Energy Credits for Compliance
7,210

 
4,844

Deferred Income Taxes
4,339

 
5,337

Pension and Retiree Expense
4,647

 
3,412

Pension and Retiree Funding
(2,624
)
 
(1,657
)
Share-Based Compensation Expense
656

 
792

Allowance for Equity Funds Used During Construction
(343
)
 
(1,721
)
LFCR and DSM Revenues
(5,461
)
 
(6,226
)
Increase (Decrease) to Reflect PPFAC Recovery
3,249

 
(1,730
)
Changes in Assets and Liabilities which Provided (Used)
 
 
 
Cash Exclusive of Changes Shown Separately
 
 
 
Accounts Receivable
9,947

 
16,274

Materials and Fuel Inventory
(4,239
)
 
(3,182
)
Accounts Payable
(12,046
)
 
(3,425
)
Interest Accrued
(2,559
)
 
(3,260
)
Taxes Other Than Income Taxes
11,372

 
9,948

Other
(2,621
)
 
(1,809
)
Net Cash Flows – Operating Activities
67,488

 
65,314

Cash Flows from Investing Activities
 
 
 
Capital Expenditures
(99,291
)
 
(72,570
)
Purchase of Intangibles—Renewable Energy Credits
(6,325
)
 
(5,431
)
Purchase of Springerville Unit 1 Lease Assets
(45,753
)
 

CIAC
959

 
5,746

Other, net

 
1,664

Net Cash Flows—Investing Activities
(150,410
)
 
(70,591
)
Cash Flows from Financing Activities
 
 
 
Proceeds from Borrowings Under Revolving Credit Facility
15,000

 
105,000

Repayments of Borrowings Under Revolving Credit Facility
(100,000
)
 
(105,000
)
Proceeds from Borrowings Under Term Loan
130,000

 

Repayments of Borrowings Under Term Loan
(130,000
)
 

Proceeds from Issuance of Long-Term Debt
299,019

 
149,168

Repayments of Long-Term Debt
(130,000
)
 

Payments of Capital Lease Obligations
(8,394
)
 
(79,737
)
Payment of Debt Issue/Retirement Costs
(2,372
)
 
(1,471
)
Other, net
847

 
3

Net Cash Flows—Financing Activities
74,100

 
67,963

Net Increase (Decrease) in Cash and Cash Equivalents
(8,822
)
 
62,686

Cash and Cash Equivalents, Beginning of Year
74,170

 
25,335

Cash and Cash Equivalents, End of Period
$
65,348

 
$
88,021

See Notes to Condensed Consolidated Financial Statements.


5



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY
 
Common Shares
 
Common
Stock
 
Capital
Stock Expense
 
Retained Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Total
Stockholder's Equity
 
(Unaudited)
 
Amounts in Thousands
Balances at December 31, 2014
32,139

 
$
1,116,539

 
$
(6,357
)
 
$
111,523

 
$
(5,926
)
 
$
1,215,779

Net Income
 
 
 
 
 
 
9,429

 
 
 
9,429

Other Comprehensive Income, net of tax
 
 
 
 
 
 
 
 
74

 
74

Balances at March 31, 2015
32,139

 
$
1,116,539

 
$
(6,357
)
 
$
120,952

 
$
(5,852
)
 
$
1,225,282

See Notes to Condensed Consolidated Financial Statements.


6

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION
Tucson Electric Power Company (TEP) is a regulated utility that generates, transmits and distributes electricity to approximately 417,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly owned subsidiary of UNS Energy Corporation (UNS Energy), a utility services holding company. UNS Energy is an indirect wholly owned subsidiary of Fortis Inc. (Fortis), which is a leader in the North American electric and gas utility business.
BASIS OF PRESENTATION
We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP), including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements. See Note 2. The condensed consolidated financial statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generating stations and transmission facilities with both affiliated and non-affiliated entities. TEP's proportionate share of jointly owned facilities is recorded as Utility Plant on the condensed consolidated balance sheets, and our proportionate share of the operating costs associated with these facilities is included in the condensed consolidated statements of income. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 2014 Annual Report on Form 10-K.
The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, our quarterly results are not indicative of annual operating results.
In 2014, following the acquisition of UNS Energy by Fortis, TEP elected to change its method of reporting cash flows from the direct to the indirect method to conform to the presentation method elected by Fortis. Certain amounts from prior periods have been reclassified to conform to the current period presentation.
RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
In 2015, we adopted accounting guidance that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. The adoption of this guidance did not have any impact on our disclosures, financial condition, results of operations, or cash flows.

NOTE 2. REGULATORY MATTERS
The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales.
COST RECOVERY MECHANISMS
Purchased Power and Fuel Adjustment Clause
The ACC adjusts TEP's Purchased Power and Fuel Adjustment Clause (PPFAC) rate annually each April 1 for the subsequent 12-month period. The ACC approved rates of 0.50 cents per Kilowatt-hours (kWh) for the three months ended March 31, 2015 and 0.14 cents per kWh for the three months ended March 31, 2014. In March 2015, the ACC approved a PPFAC rate for TEP of 0.68 cents per kWh for the period April 2015 through March 2016.
In September 2011, a fire at the underground mine providing coal to San Juan Generating Station (San Juan) caused interruptions to mining operations and resulted in increased fuel costs. The 2013 TEP Rate Order required TEP to defer incremental fuel costs of $10 million from recovery under the PPFAC pending final resolution of an insurance claim by the San Juan Coal Company and distribution of insurance proceeds to San Juan participants. As of March 31, 2015, TEP has received insurance settlement proceeds of $8 million. The proceeds offset the deferred costs and are reflected in our cash flow

7

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



statements as an other operating cash receipt. TEP expects to recover any remaining incremental fuel costs, not reimbursed by insurance, through its PPFAC.
Environmental Compliance Adjustor
The 2013 TEP Rate Order provided an Environmental Compliance Adjustor (ECA) to recover the return on and of qualified investments, including related operating expenses, to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP recognized ECA revenues of less than $0.5 million in the first three months of 2015.
Energy Efficiency Standards
TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs as well as an annual performance incentive. In the first three months of 2015, TEP recorded an annual DSM performance incentive of $3 million related to savings realized in 2014 that is included in the Electric Retail Sales line item in the accompanying condensed consolidated statements of income.
Lost Fixed Cost Recovery Mechanism
The Lost Fixed Cost Recovery (LFCR) mechanism provides recovery of certain non-fuel costs that would go unrecovered due to lost retail kWh sales as a result of implementing ACC approved EE programs and distributed generation (DG) targets. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. For recovery of the LFCR regulatory asset, TEP is required to file an annual LFCR adjustment request with the ACC for the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year cap of 1% of the company's total retail revenues.
TEP recorded a regulatory asset and recognized LFCR revenues of $3 million in the first three months of 2015 and $5 million in the first three months of 2014. LFCR revenues are included in the Electric Retail Sales in the accompanying condensed consolidated statements of income.
The ACC approved recovery of $5 million through the LFCR recovery mechanism effective August 2014 for the subsequent 12-month period.
REGULATORY ASSETS
TEP's total regulatory assets, including current and noncurrent assets, increased $25 million at March 31, 2015 from December 31, 2014, primarily due to the reclassification of unamortized leasehold improvement costs upon expiration of the Springerville Unit 1 capital lease in January 2015 that relate to third-party ownership interests. These leasehold improvements, previously recorded in Plant in Service, represent investments TEP made through the end of the lease term to ensure that the Springerville facilities continued providing safe, reliable service to TEP's customers. In its 2013 Rate Case, TEP requested and received ACC authorization to use a 10-year amortization period for leasehold improvements at Springerville Unit 1. TEP owns a 49.5% undivided interest in Springerville Unit 1.

NOTE 3. RELATED PARTY TRANSACTIONS
TEP engages in various transactions with Fortis, Inc., UNS Energy and its affiliated subsidiaries including Unisource Energy Services, Inc., UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy affiliates). These transactions include sales and purchases of power, common cost allocations, and the provision of corporate and other labor related services.

8

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



At March 31, 2015 and December 31, 2014, our balance sheets include the following intercompany balances:
 
Balances at
 
March 31, 2015
 
December 31, 2014
 
Millions of Dollars
Receivables from Related Parties
 
 
 
UNS Electric
$
4

 
$
4

UNS Gas
1

 
1

Total Due from Related Parties
$
5

 
$
5

 
 
 
 
Payables to Related Parties
 
 
 
SES
$
3

 
$
2

UNS Energy
1

 

UNS Electric

 
1

Total Due to Related Parties
$
4

 
$
3

The following table summarizes related party transactions:
 
Three Months Ended March 31,
 
2015
 
2014
 
Millions of Dollars
Wholesale Sales - TEP to UNS Electric (1)
$
2

 
$

Control Area Services - TEP to UNS Electric (2)

 
1

Common Costs - TEP to UNS Energy Affiliates (3)
3

 
3

Supplemental Workforce - SES to TEP (4)
4

 
4

Corporate Services - UNS Energy to TEP (5)
1

 
1

(1) 
TEP sells power to UNS Electric at prevailing market prices.
(2) 
TEP charges UNS Electric for control area services under a FERC-accepted Control Area Services Agreement.
(3) 
Common costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. Management believes this method of allocation is reasonable.
(4) 
SES provides supplemental workforce and meter-reading services to TEP. Amounts are based on costs of services performed, and management believes that the charges for the services are reasonable.
(5) 
Corporate costs at UNS Energy, such as Fortis management fees, legal fees, and audit fees, are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 81% of UNS Energy's allocated costs. For the three months ended March 31, 2015 these costs included approximately $1 million in Fortis management fees and for the three months ended March 31, 2014 these costs included approximately $1 million in merger related costs.
Share-Based Compensation Expense
In January 2015, UNS Energy established a new share-based compensation plan, referred to as the 2015 Share Unit Plan (the Plan), to promote greater alignment of interests between the senior management of UNS Energy and its subsidiaries and the shareholders of Fortis. TEP recognized less than $1 million of share-based compensation expense under the Plan for the three months ended March 31, 2015. For the three months ended March 31, 2014, TEP recognized less than $1 million of expense under UNS Energy's prior share-based compensation plan.

NOTE 4. DEBT AND CAPITAL LEASE OBLIGATIONS
We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2014 Annual Report on Form 10-K.

9

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



CAPITAL LEASE OBLIGATIONS
Springerville Unit 1 Capital Lease Purchase
In January 2015, TEP purchased leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million, the appraised value. With the completion of the lease option purchase, TEP owns 49.5% of Springerville Unit 1, or 192 MW of capacity. Furthermore, TEP is obligated to operate the unit for the Third-Party Owners under an existing facility support agreement. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses. See Note 5.
Springerville Coal Handling Facilities Lease Purchase Commitment
In April 2015, upon the expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million, bringing its total ownership of the assets to 100%. With the completion of this purchase, Salt River Project Agricultural Improvement and Power District (SRP) is obligated to purchase a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State Generation and Transmission Association, Inc. (Tri-State) is obligated to either: 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. TEP expects SRP to complete its purchase commitment in the second quarter 2015. Tri-State has until April 2016 to elect an option. At March 31, 2015, no amounts have been recorded on TEP's balance sheet for commitments from either SRP or Tri-State.
UNSECURED BOND ISSUANCES AND REDEMPTIONS
In January 2015, amounts borrowed under the 2014 Credit Agreement term loan portion were used to purchase $130 million aggregate principal amount of unsecured Industrial Development Revenue Bonds (IDRBs) issued in June 2008 by the Industrial Development Authority of Pima County for the benefit of TEP. These multi-modal bonds currently bear interest at a fixed rate of 5.75% and mature in September 2029. TEP did not cancel the purchased bonds and had not remarketed them as of March 31, 2015; therefore, they are not reflected as debt on the balance sheet.
In February 2015, TEP issued and sold $300 million aggregate principal amount of its senior unsecured notes bearing interest at the fixed rate of 3.05% and maturing March 15, 2025. TEP may redeem the notes prior to December 15, 2024, with a make-whole premium plus accrued interest. On or after December 15, 2024, TEP may redeem the notes at par plus accrued interest. Interest on the notes will be payable semi-annually on each March 15 and September 15, beginning September 15, 2015, and at maturity.
In March 2015, TEP used the net proceeds from the sale to repay $215 million of revolving and term loans under its 2014 Credit Agreement and 2010 Credit Agreement. See Credit Agreements below. In April 2015, TEP used the remaining amount to pay a portion of the purchase price for its ownership interests in the Springerville Coal Handling Facilities.
CREDIT AGREEMENTS
2014 Credit Agreement
In March 2015, net proceeds from the sale of senior unsecured notes were used to repay the 2014 Credit Agreement's $70 million outstanding revolver borrowings and $130 million outstanding term loan. The $130 million term loan portion cannot be reborrowed per the terms of the agreement. See Unsecured Bond Issuances and Redemptions above.
As of March 31, 2015, there was $70 million available under the revolving credit facility of the 2014 Credit Agreement. As of May 4, 2015, TEP had nothing available under the 2014 Credit Agreement revolving credit facility.
2010 Credit Agreement
Interest rates and fees under the 2010 Credit Agreement are based on a pricing grid tied to TEP’s credit ratings. With Moody's Investors Service, Inc. (Moody's) increase to TEP's credit rating in February 2015, the interest rate currently in effect on borrowings decreased to LIBOR plus 1.00% for Eurodollar loans or Alternate Base Rate plus 0.00% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million Letter of Credit (LOC) facility decreased to 1.00%.
In March 2015, net proceeds from the sale of senior unsecured notes were used to repay $15 million of revolver borrowings outstanding. See Unsecured Bond Issuances and Redemptions above.
As of March 31, 2015, there was $200 million available under the revolving credit facility of the 2010 Credit Agreement. As of May 4, 2015, TEP had $142 million available under the 2010 Credit Agreement revolving credit facility.

10

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



2010 TEP REIMBURSEMENT AGREEMENT
The 2010 TEP Reimbursement Agreement supports $37 million aggregate principal amount of variable rate tax-exempt bonds and includes fees payable on the aggregate outstanding amount. The rate currently in effect decreased to 0.75% per annum after credit rating upgrade in February 2015.
COVENANT COMPLIANCE
At March 31, 2015, we were in compliance with the terms of our loan and credit agreements.

NOTE 5. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS
COMMITMENTS
In addition to those reported in our 2014 Annual Report on Form 10-K, TEP entered into the following long-term commitments through March 31, 2015:
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
 
Total
 
Millions of Dollars
Fuel, Including Transportation
$
1

 
$
2

 
$
2

 
$
2

 
$
2

 
$
47

 
$
56

Purchased Power
30

 
11

 

 

 

 

 
41

   Total Purchase Commitments
$
31

 
$
13

 
$
2

 
$
2

 
$
2

 
$
47

 
$
97

CONTINGENCIES
Navajo Generating Station Lease Extension
Navajo Generating Station (Navajo) is located on a site that is leased from the Navajo Nation with an initial lease term through 2019. The Navajo Nation signed a lease amendment that would extend the lease from 2019 through 2044. The participants in Navajo, including TEP, have not signed the lease amendment. Certain participants have expressed an interest in discontinuing their participation in Navajo. Negotiations are ongoing, and all parties will likely agree to the terms. To become effective, this lease amendment must be signed by all of the participants, approved by the Department of the Interior, and is subject to environmental reviews. TEP owns 7.5% of Navajo. In the first quarter of 2015, TEP recorded additional estimated lease expense of approximately $1 million with the expectation that the lease amendment will become effective. At March 31, 2015, TEP's balance sheet reflects a total liability related to the lease amendment of $3 million recorded in Deferred Credits and Other Liabilities—Other.
Claims Related to Springerville Generating Station Unit 1
On November 7, 2014, the Springerville Unit 1 Third-Party Owners filed a complaint (FERC Action) against TEP at the FERC alleging that TEP had not agreed to wheel power and energy for the Third-Party Owners in the manner specified in the Springerville Unit 1 facility support agreement between TEP and the Third-Party Owners and for the cost specified by the Third-Party Owners. The Third-Party Owners requested an order from the FERC requiring such wheeling of the Third-Party Owners’ energy from their Springerville Unit 1 interests beginning on January 1, 2015 to the Palo Verde switchyard and for the price specified by the Third-Party Owners. On December 3, 2014, TEP filed an answer to the FERC Action denying the allegations and requesting that the FERC dismiss the complaint. On February 19, 2015, the FERC issued an order denying the Third-Party Owners complaint. On March 23, 2015, the Third-Party Owners filed a request for rehearing in the FERC Action. On April 7, 2015, TEP filed an answer in response to the request for rehearing. The FERC has not yet ruled on the request for rehearing.
On December 19, 2014, the Third-Party Owners filed a complaint against TEP in the Supreme Court of the State of New York, New York County (New York Action), alleging, among other things, that TEP has refused to comply with the Third-Party Owners' instructions to schedule their entitlement share of power and energy, that TEP failed to comply with their instructions to specify the level of fuel and fuel handling services, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases, that TEP has not agreed to wheel power and energy in the manner required as set forth in the FERC Action, and that TEP has breached fiduciary duties claimed to be owed to the Third-Party Owners. The New York Action seeks declaratory judgments, injunctive relief, damages in an amount to be determined at trial and the Third-Party Owners’ fees and expenses. On February 20, 2015, TEP filed a motion to dismiss in the New York Action that requested that the court dismiss various counts of the complaint. On March 20, 2015, the Third-Party Owners filed

11

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



a first amended complaint which includes all the counts that were in the original complaint except those alleging that TEP refused to comply with the Third-Party Owners instructions to schedule power and energy and to specify the level of fuel and fuel handling services, which have been dropped. The amended complaint also includes new counts alleging that TEP has failed to pay the Third-Party Owners approximately $71 million in liquidated damages they allege they are owed (see following paragraph), that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired, that TEP has converted the Third-Party Owners’ water rights and that TEP has been unjustly enriched as a result, and that TEP has breached the lease transaction documents by refusing to pay certain of the Third-Party Owners’ claimed expenses. On April 20, 2015, TEP filed a motion to compel arbitration and to dismiss or stay certain counts of the amended complaint in the New York Action.
On December 22, 2014, Wilmington Trust Company, as Owner Trustees and Lessors under the leases of the Third-Party Owners, sent a notice to TEP that alleges that TEP has defaulted under the Third-Party Owners’ leases. The notice states that the Owner Trustees, as Lessors, are exercising their rights to keep the undivided interests idle and demanding that TEP pay, on January 1, 2015, liquidated damages totaling approximately $71 million. On January 26, 2015, Wilmington Trust Company sent a second notice repeating the allegations in the December 22, 2014 notice. In a letter to Wilmington Trust Company, TEP denied the allegations in the second notice.
On April 20, 2015, TEP filed a demand for arbitration with the American Arbitration Association seeking an award of the Third-Party Owners share of unreimbursed expense and capital expenditures for Springerville Unit 1. As of March 31, 2015, TEP has billed the Third-Party Owners approximately $6 million for their pro-rata share of Springerville Unit 1 expenses and less than $0.5 million for their pro-rata share of capital costs, none of which has been paid as of May 4, 2015.
TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the injunctive relief sought for these claims, TEP cannot determine estimates of the range of loss at this time. TEP intends to vigorously defend itself against the claims asserted by the Third-Party Owners.
Claims Related to San Juan Generating Station
San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.
In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.
In February 2013, WildEarth Guardians (WEG) filed a Petition for Review in the United States District Court of Colorado against the Office of Surface Mining (OSM) challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act (NEPA) violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The Court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico, where this matter is now proceeding. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and San Juan. TEP cannot currently predict the outcome of this matter or the range of its potential impact.

12

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Claims Related to Four Corners Generating Station
In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all claims asserted by EarthJustice in the amended complaint. The parties exchanged settlement proposals in January and February 2015, and have agreed to have the matter stayed until June 1, 2015 to make continued progress toward a final agreement that would resolve this matter without further litigation. A final consent decree version is currently being circulated for signature by all of the parties.
TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP's estimated share of the settlement offer submitted by APS in August 2014 is less than $1 million. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for this claim, TEP cannot determine estimates of the range of costs at this time.
In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. In December 2013, the coal supplier and Four Corners’ operating agent filed a claim contesting the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. TEP cannot predict the final outcome or timing of resolution of this claim.
Mine Closure Reclamation at Generating Stations Not Operated by TEP
TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $52 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability recorded was $23 million at March 31, 2015 and $22 million at December 31, 2014.
Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.
TEP’s PPFAC allows us to pass through final reclamation costs, as a component of fuel cost, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.
Discontinued Transmission Project
TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. At this time, TEP and UNS Electric will not proceed with the project based on the cost of the proposed 345-Kilo-volt (kV) line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC that recent transmission additions by TEP and UNS Electric support elimination of this project. TEP and UNS Electric plan to maintain the Certificate of Environmental Compatibility (CEC) previously granted by the ACC for this project in contemplation of using the route, or a portion thereof, to serve future customers and to address reliability needs. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from the FERC before seeking rate recovery from the ACC. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery in TEP's next FERC rate case.
Performance Guarantees
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-

13

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



defaulting participants have agreed to bear a proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generating capacity of the defaulting participants. As of March 31, 2015, there have been no such payment defaults under any of the remote generating station agreements. TEP's joint participation agreements for the San Juan, Navajo, Four Corners and Luna generating facilities expire in 2019 through 2046.
ENVIRONMENTAL MATTERS
Environmental Regulation
The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.
Coal Combustion Residuals Regulations
In April 2015, the EPA issued a final rule requiring all coal ash and other coal combustion residuals to be treated as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) while allowing for the continued recycling of coal ash. TEP is in the process of evaluating the final impacts of the rule on our coal fired generation. However, TEP does not anticipate significant impacts to our existing facilities where coal combustion residual are managed. The additional requirements would apply to lateral expansion of those existing landfills or to any new landfill.
Hazardous Air Pollutant Requirements
In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics Standards (MATS) rules, additional emission control equipment would have been required by April 2015. However, TEP, as operator of Springerville and Sundt, and the operator of Navajo have received extensions until April 2016 to comply with the MATS rules. TEP's share of the estimated costs to comply with the MATS rules includes the following:
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 Springerville Units 1 & 2, with estimated costs split equally between the two units. In January 2015, TEP completed the purchase of 49.5% of Springerville Unit 1. With the completion of the purchase, Third Party Owners are responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
TEP expects Four Corners, Sundt, and San Juan's current emission controls to be adequate to comply with the EPA's MATS rules. A study determined that Four Corners' emission controls are adequate. Therefore, TEP expects no additional capital expenditures or O&M expenses will be incurred to comply. Although expected to be compliant, Sundt would be required to install additional monitoring equipment, at an estimated cost of less than $1 million, to continue to burn coal after the MATS rules become effective.
Regional Haze Rules
The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on 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 BART rules, and with other future environmental rules, may make it economically impractical to continue operating all or a portion of the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. These BART provisions do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other

14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018. TEP cannot predict the ultimate outcome of these matters.
TEP's estimated costs involved in meeting these rules are:
Estimated NOx Emissions Control Costs:
Navajo (1)
 
San Juan (2)
 
Four Corners (3)
 
Sundt (4)
 
Millions of Dollars
Capital Expenditures
$
28

 
$
37

 
$
44

 
$
12

Annual O&M Expenses
1

 
1

 
2

 
5-6

(1) 
In August 2014, the EPA published a final Federal Implementation Plan (FIP) wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. The final BART includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA which option will be implemented. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $28 million with O&M on the baghouses expected to be less than $1 million per year.
(2)
In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by December 2017 and the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4 by February 2016. TEP owns 50% of Units 1 and 2 at San Juan. TEP expects its share of the cost to install SNCR technology on San Juan Unit 1 to be approximately $12 million. Additionally, the SIP approval references a New Source Review permit issued by the New Mexico Environment Department in November 2013 which, among other things, calls for balanced draft upgrades on San Juan Unit 1 to reduce particulate matter emissions. Public Service Company of New Mexico (PNM), the operator of San Juan, is currently installing SNCR and making the necessary balanced draft modifications to San Juan Unit 1. TEP’s share of the balanced draft upgrades is expected to be approximately $25 million for a total of $37 million in capital expenditures. TEP's share of incremental annual operating costs for SNCR for San Juan Unit 1 is estimated at $1 million. Prior to the shutdown of any units at San Juan, PNM, the operator, must first obtain New Mexico Public Regulation Commission approval. At March 31, 2015, the net book value of TEP's share in San Juan Unit 2 was $109 million. TEP submitted a depreciation study in its 2013 Rate Case which identified an excess of required generation depreciation reserves. As stipulated in the 2013 Rate Order, TEP will seek the ACC's authority to apply any excess generation depreciation reserves to the unrecovered book value of any early retirement of generation assets prior to seeking additional recovery. TEP expects the excess generation depreciation reserves to fully cover the costs associated with early retirement of Unit 2.
(3)
In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 and 5 by July 2018. TEP owns 7% of Four Corners Units 4 and 5.
(4)
In June 2014, the EPA issued a final rule that would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At March 31, 2015, the net book value of the Sundt coal handling facilities was $17 million. If the coal handling facilities are retired early, TEP will request ACC approval to recover all the remaining costs of the coal handling facilities.


15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



NOTE 6. EMPLOYEE BENEFIT PLANS
Net periodic benefit plan cost includes the following components:
 
Pension Benefits
 
Other Retiree Benefits
 
Three Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
 
Millions of Dollars
Service Cost
$
3

 
$
2

 
$
1

 
$
1

Interest Cost
4

 
4

 
1

 

Expected Return on Plan Assets
(6
)
 
(5
)
 

 

Actuarial Loss Amortization
2

 
1

 

 

Net Periodic Benefit Cost
$
3

 
$
2

 
$
2

 
$
1


NOTE 7. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
We categorize our assets and liabilities accounted for at fair value into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.
FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS
The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)
 
Net Amount
 
March 31, 2015
 
Millions of Dollars
Assets
 
 
 
Cash Equivalents(1)
$
50

 
$
50

 
$

 
$

 
$

 
$
50

Restricted Cash(1)
2

 
2

 

 

 

 
2

Rabbi Trust Investments(2)
27

 

 
27

 

 

 
27

Energy Contracts - Regulatory Recovery(3)
1

 

 

 
1

 
(1
)
 

Total Assets
80

 
52

 
27

 
1

 
(1
)
 
79

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Energy Contracts - Regulatory Recovery(3)
(25
)
 

 
(13
)
 
(12
)
 
1

 
(24
)
Energy Contracts - Cash Flow Hedge(3)
(1
)
 

 

 
(1
)
 

 
(1
)
Interest Rate Swaps(4)
(4
)
 

 
(4
)
 

 

 
(4
)
Total Liabilities
(30
)
 

 
(17
)
 
(13
)
 
1

 
(29
)
Net Total Assets (Liabilities)
$
50

 
$
52

 
$
10

 
$
(12
)
 
$

 
$
50


16


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



 
Total
 
Level 1
 
Level 2
 
Level 3
 
Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)
 
Net Amount
 
December 31, 2014
 
Millions of Dollars
Assets
 
 
 
Cash Equivalents(1)
$
15

 
$
15

 
$

 
$

 
$

 
$
15

Restricted Cash(1)
2

 
2

 

 

 

 
2

Rabbi Trust Investments(2)
26

 

 
26

 

 

 
26

Energy Contracts - Regulatory Recovery(3)
2

 

 

 
2

 
(2
)
 

Total Assets
45

 
17

 
26

 
2

 
(2
)
 
43

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Energy Contracts - Regulatory Recovery(3)
(18
)
 

 
(9
)
 
(9
)
 
1

 
(17
)
Energy Contracts - No Regulatory Recovery(3)
(1
)
 

 

 
(1
)
 
1

 

Energy Contracts - Cash Flow Hedge(3)
(1
)
 

 

 
(1
)
 

 
(1
)
Interest Rate Swaps(4)
(5
)
 

 
(5
)
 

 

 
(5
)
Total Liabilities
(25
)
 

 
(14
)
 
(11
)
 
2

 
(23
)
Net Total Assets (Liabilities)
$
20

 
$
17

 
$
12

 
$
(9
)
 
$

 
$
20

(1) 
Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets.
(2) 
Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets.
(3) 
Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), forward power purchase and sales contracts (Level 3) entered into to reduce exposure to energy price risk, and, at December 31, 2014, a power sale option. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
(4) 
An Interest Rate Swap valued using an income valuation approach, based on the 6-month London Interbank Offered Rate (LIBOR) is included in Derivative Instruments on the balance sheets.
(5) 
All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets.
DERIVATIVE INSTRUMENTS
We enter into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with our gas and purchased power requirements. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC.
We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.
For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, or industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe that the market information provided is reflective of market conditions as of the time and date indicated.
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, we apply adjustments based on historical price curve relationships, transmission, and line losses.

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves.
The December 31, 2014 valuation of our power sale option was a function of observable market variables, regional power and gas prices, as well as the ratio between the two, which represents the prevailing market heat rate.
We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no transfers between levels in the periods presented.
We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data.
The inputs and our assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We review the assumptions underlying our price curves monthly.
Cash Flow Hedges
We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. The interest rate swap agreement expires January 2020. The realized loss recorded to Capital Lease Interest Expense was less than $0.5 million for the three months ended March 31, 2015 and less than $1 million for the three months ended March 31, 2014. The realized loss recorded to Long-Term Debt Interest Expense for three months ended March 31, 2014 was less than $0.5 million. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. The power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statements of other comprehensive income. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million.
Energy Contracts - Regulatory Recovery
We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following table:
 
 
Three Months Ended March 31,
 
 
2015
 
2014
 
Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets)/Liabilities
 
$
(6
)
 
$
1

Energy Contracts - No Regulatory Recovery
Forward contracts with long-term wholesale customers do not qualify for regulatory recovery. For these contracts that qualify as derivatives, we record unrealized gains and losses in the income statement, unless and until a normal purchase or normal sale election is made. In the first quarter of 2015, TEP made a normal sale election for a three-year sales option contract entered into in December 2014.
Derivative Volumes
At March 31, 2015, we have energy contracts that will settle through the first quarter of 2018. The volumes associated with our energy contracts were as follows:
 
 
March 31, 2015
 
December 31, 2014
Power Contracts GWh
 
1,008

 
2,604

Gas Contracts GBtu
 
24,027

 
19,932


18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Level 3 Fair Value Measurements
The following table provides quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:
 
 
 
Fair Value at 
 
 
 
 
 
 
 
Valuation
 
March 31, 2015
 
 
 
Range of
 
Approach
 
Assets
 
Liabilities
 
Unobservable Inputs
 
Unobservable Input
 
 
 
Millions of Dollars
 
 
 
 
 
 
Forward Power Contracts
Market approach
 
$
1

 
$
(8
)
 
Market price per MWh
 
$
23.80

 
$
37.70


 
 
 
 
 
 
 
 
 
 
 
Gas Option Contracts
Option model
 

 
(5
)
 
Market price per MMbtu
 
$
2.34

 
$
3.22


 
 
 
 
 
 
Gas volatility
 
24.15
%
 
39.91
%
Level 3 Energy Contracts
 
 
$
1

 
$
(13
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value at 
 
 
 
 
 
 
 
Valuation
 
December 31, 2014
 
 
 
Range of
 
Approach
 
Assets
 
Liabilities
 
Unobservable Inputs
 
Unobservable Input
 
 
 
Millions of Dollars
 
 
 
 
 
 
Forward Power Contracts
Market approach
 
$
1

 
$
(6
)
 
Market price per MWh
 
$
22.35

 
$
39.05

 
 
 
 
 
 
 
 
 
 
 
 
Power Sale Option
Market approach
 
1

 
(1
)
 
Market price per MWh
 
$
27.75

 
$
44.94

 
 
 
 
 
 
 
Market price per MMbtu
 
$
2.88

 
$
4.02

 
 
 
 
 
 
 
 
 
 
 
 
Gas Option Contracts
Option model
 

 
(4
)
 
Market price per MMbtu
 
$
2.72

 
$
3.26

 
 
 
 
 
 
 
Gas volatility
 
30.8
%
 
53.29
%
Level 3 Energy Contracts
 
 
$
2

 
$
(11
)
 
 
 
 
 
 
 
Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, that are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.
The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:
 
 
Three Months Ended March 31,
 
 
2015
 
2014
 
 
Millions of Dollars
Balances at December 31
 
$
(9
)
 
$
(2
)
Realized/Unrealized Gains/(Losses) Recorded to:
 
 
 
 
Net Regulatory Assets/Liabilities – Derivative Instruments
 
(2
)
 
(1
)
Settlements
 
(1
)
 
1

Balances at March 31
 
$
(12
)
 
$
(2
)
 
 
 
 
 
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/(Liabilities) Still Held at the End of the Period
 
$
(3
)
 
$


19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



CREDIT RISK
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value.
We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.
We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts.
Material adverse changes could trigger credit risk-related contingent features. At March 31, 2015, the value of derivative instruments in a net liability position under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $27 million, compared with $21 million at December 31, 2014. At March 31, 2015, TEP had no cash collateral posted and less than $0.5 million of LOCs as credit enhancements with its counterparties and held no collateral from its counterparties. The additional collateral to be posted if credit-risk contingent features were triggered would be $27 million.
FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE
The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:
The carrying amounts of our current maturities of long-term debt and amounts outstanding under our credit agreements approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.
For Long-Term Debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:
 
 
 
March 31, 2015
 
December 31, 2014
 
Fair Value
Hierarchy
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
 
 
Millions of Dollars
Long-Term Debt
Level 2
 
$
1,541

 
$
1,642

 
$
1,372

 
$
1,457



20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

NOTE 8. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. The revenue standard requires entities to apply the guidance retrospectively or recognize the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings supplemented by additional disclosures. On April 1, 2015, the FASB proposed to defer the effective date of the revenue recognition standard by one year. Based on the proposed effective date, we will be required to adopt the new guidance for annual and interim periods beginning January 1, 2018; early adoption is permitted for annual and interim periods beginning January 1, 2017. We are in the process of identifying contracts with customers and performance obligations in contracts.
In June 2014, the FASB issued guidance that requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. An entity can elect to adopt the amendment prospectively or retrospectively. TEP does not expect the adoption of this guidance to have a material impact on our disclosures, financial condition, results of operations, or cash flows.
In August 2014, the FASB issued guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide related disclosures. This update is effective for annual and interim periods beginning January 1, 2017; early adoption is permitted. TEP does not expect the adoption of this guidance to have an impact on its disclosures.
In January 2015, the FASB issued an accounting standards update that removes the concept of extraordinary items from U.S. GAAP. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. TEP does not expect the adoption of this guidance to impact its results of operations or disclosures.
In February 2015, the FASB issued guidance that amends the current consolidation guidance; the amendment affects both the variable interest entity and voting interest entity consolidation models. This standard is effective beginning January 1, 2016; early adoption is permitted. We are evaluating the impact to our financial statements and disclosures.
In April 2015, the FASB issued guidance which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, rather than as deferred charges. The amendment is effective for periods beginning January 1, 2016 and will be applied retrospectively; early adoption is permitted. The adoption of this standard is expected to result in reclassification of debt issuance costs from Other Current Assets and Other Assets to Long-Term Debt on our balance sheet. TEP’s deferred debt issuance costs associated with long-term debt outstanding totaled $12 million at March 31, 2015 and $11 million at December 31, 2014, of which approximately $1 million is classified as current at each date.
In April 2015, the FASB issued guidance that will help entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement either as a software license or a service contract. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. An entity can elect to adopt the amendment prospectively or retrospectively. TEP does not expect the adoption of this guidance to have a material impact on our disclosures, financial condition, results of operations, or cash flows.


21


ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for TEP. It includes the following:
outlook and strategies;
operating results during the first quarter of 2015 compared with the first quarter of 2014;
factors affecting our results and outlook;
liquidity and capital resources including contractual obligations;
critical accounting estimates; and
recent accounting pronouncements.

OVERVIEW
Tucson Electric Power Company (TEP) is a vertically integrated, regulated utility that generates, transmits and distributes electricity to approximately 417,000 retail electric customers in a 1,155 square mile area in southeastern Arizona.
Management’s Discussion and Analysis includes financial information prepared in accordance with generally accepted accounting principles (GAAP) in the U.S., as well as certain non-GAAP financial measures. The non-GAAP financial measures should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP measures as presented herein may not be comparable to similarly titled measures used by other companies.
Management’s Discussion and Analysis should be read in conjunction with the Condensed Consolidated Financial Statements and Notes that appear in Item 1 of this Form 10-Q. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see Forward-Looking Information at the front of this report and Risk Factors in Part 1, Item 1A of our 2014 Form 10-K and in Part II, Item 1A of this report.
References in this report to "we" and "our" are to TEP.

OUTLOOK AND STRATEGIES
TEP's financial prospects and outlook are affected by many factors including: national, regional, and local economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:
Continuing to focus on our long-term generation resource strategy including shifting from coal to natural gas, renewables, and energy efficiency while providing rate stability for our customers, mitigating environmental impacts, complying with regulatory requirements, and leveraging our existing utility infrastructure.
Developing strategic responses to new environmental regulations and potential new legislation, including proposed carbon emission standards to reduce greenhouse gas emissions from existing power plants. We are evaluating TEP's existing mix of generation resources and defining steps to achieve environmental objectives that protect the financial stability of our utility business and the interests of our customers.
Strengthening the underlying financial condition of TEP by achieving constructive regulatory outcomes, improving our capital structure and our credit ratings, and promoting economic development in our service territory.
Focusing on our core utility business through operational excellence, investing in utility rate base, emphasizing customer service, and maintaining a strong community presence.
Developing strategic responses to the evolving utility business that includes renewable energy, DG, and EE that protect the financial stability of our business while providing benefits and choices to our customers.


22



RESULTS OF OPERATIONS
The following discussion provides the significant items that affected TEP's results of operations for the three month periods ended March 31, 2015 and 2014.
First quarter of 2015 compared with the first quarter of 2014
TEP's reported net income of $9 million in the first quarter of 2015 was unchanged from the first quarter of 2014. The following factors impacted TEP’s 2015 results when compared with the first quarter of 2014. All amounts are presented on an after-tax basis:
a $2 million decrease in the margin on long-term wholesale sales due in part to a decrease in the average market price for wholesale power; and
a $2 million increase in depreciation and amortization expenses, resulting primarily from an increase in asset base in the current period; partially offset by
a $1 million decrease in Base O&M principally due to a decrease in generation expenses;
a $1 million increase in transmission revenues;
a $1 million decrease in interest expense, primarily due to a reduction in the balance of capital lease obligations. See Note 5 to the Condensed Consolidated Financial Statements; and
a $1 million increase in retail margin revenue.

23


Utility Sales and Revenues
The table below provides a summary of retail kWh sales, revenues, and weather data during the first quarter of 2015 and 2014:
 
Three Months Ended March 31,
 
Increase (Decrease)
 
2015
 
2014
 
Amount
 
Percent
Energy Sales, kWh (in Millions):
 
 
 
 
 
 
 
Electric Retail Sales:
 
 
 
 
 
 
 
Residential
680

 
668

 
12

 
1.8
 %
Commercial
434

 
444

 
(10
)
 
(2.3
)%
Industrial
463

 
471

 
(8
)
 
(1.7
)%
Mining
275

 
279

 
(4
)
 
(1.4
)%
Public Authorities
9

 
9

 

 
 %
Total Electric Retail Sales
1,861

 
1,871

 
(10
)
 
(0.5
)%
Retail Margin Revenues (in Millions):
 
 
 
 
 
 
 
Residential
$
52

 
$
51

 
$
1

 
2.0
 %
Commercial
34

 
34

 

 
 %
Industrial
22

 
22

 

 
 %
Mining
9

 
9

 

 
 %
Public Authorities
1

 
1

 

 
 %
Total by Customer Class
118

 
117

 
1

 
0.9
 %
LFCR Revenues
3

 
5

 
(2
)
 
NM

DSM Performance Bonus
3

 
1

 
2

 
NM

Total Retail Margin Revenues (Non-GAAP)(1)
124

 
123

 
1

 
0.8
 %
Fuel and Purchased Power Revenues
66

 
53

 
13

 
24.5
 %
RES, DSM, and ECA Revenues
12

 
10

 
2

 
20.0
 %
Total Retail Revenues (GAAP)
$
202

 
$
186

 
$
16

 
8.6
 %
Average Retail Margin Revenues (Cents / kWh):
 
 
 
 
 
 
 
Residential
7.65

 
7.63

 
0.02

 
0.3
 %
Commercial
7.83

 
7.66

 
0.17

 
2.2
 %
Industrial
4.75

 
4.67

 
0.08

 
1.7
 %
Mining
3.27

 
3.23

 
0.04

 
1.2
 %
Public Authorities
11.11

 
11.11

 

 
 %
Total Average Retail Margin Revenues Excluding LFCR & DSM Performance Bonus
6.34

 
6.25

 
0.09

 
1.4
 %
Average LFCR Revenues
0.16

 
0.27

 
(0.11
)
 
NM

Average DSM Performance Bonus Revenues
0.16

 
0.05

 
0.11

 
NM

Total Average Retail Margin Revenues Including LFCR & DSM Performance Bonus
6.66

 
6.57

 
0.09

 
1.4
 %
Average Fuel and Purchased Power Revenues
3.55

 
2.83

 
0.72

 
25.4
 %
Average RES, DSM, and ECA Revenues
0.64

 
0.53

 
0.11

 
20.8
 %
Total Average Retail Revenues
10.85

 
9.93

 
0.92

 
9.3
 %
 
 
 
 
 
 
Weather Data:
 
 
 
 
 
 
 
Heating Degree Days
 
 
 
 
 
 
 
Three Months Ended March 31,
433

 
429

 
4

 
0.9
 %
10-Year Average
743

 
777

 
(34
)
 
(4.4
)%
(1) 
Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues from kWh sales and Lost Fixed Cost Recovery (LFCR) revenues available to cover the non-fuel operating expenses of our core utility business.

24


Retail kWh Sales and Margin Revenues
TEP's total retail kWh sales decreased by 0.5% in the first quarter of 2015 due in part to ongoing EE programs and additions to customer-owned solar generation. Total Retail Margin Revenues increased by $1 million, or 0.8% principally due to a change in the customer mix and additional residential usage.
Wholesale Sales and Transmission Revenues
 
Three Months Ended March 31,
 
2015
 
2014
 
Millions of Dollars
Long-Term Wholesale Revenues:
 
 
 
Long-Term Wholesale Margin Revenues (Non-GAAP)(1)
$
1

 
$
3

Fuel and Purchased Power Expense Allocated to Long-Term Wholesale Revenues
7

 
5

Total Long-Term Wholesale Revenues
8

 
8

Transmission Revenues
6

 
4

Short-Term Wholesale Revenues
27

 
30

Electric Wholesale Sales (GAAP)
$
41

 
$
42

(1) 
Long-term Wholesale Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Electric Wholesale Sales, which is determined in accordance with GAAP. We believe the change in Long-Term Wholesale Margin Revenues between periods provides useful information because it demonstrates the underlying profitability of TEP’s long-term wholesale sales contracts. Long-Term Wholesale Margin Revenues represents the portion of long-term wholesale revenues available to cover the operating expenses of our core utility business.
Long-Term Wholesale Margin Revenues in the first three months of 2015 were lower when compared with the first three months of 2014 due in part to lower market prices for wholesale power.
All revenues from short-term wholesale sales are credited against the fuel and purchased power costs eligible for recovery in the Purchased Power and Fuel Adjustment Clause (PPFAC).
Other Revenues
 
Three Months Ended March 31,
 
2015
 
2014
 
Millions of Dollars
Revenue related to Springerville Units 3 and 4(1)
$
24

 
$
21

Other Revenue
6

 
6

Total Other Revenue
$
30

 
$
27

(1) 
Represents revenues and reimbursements from Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit 3, and Salt River Project Agricultural Improvement and Power District (SRP), the owner of Springerville Unit 4, to TEP related to the operation of these plants.
In addition to reimbursements related to Springerville Units 3 and 4, TEP’s other revenues include inter-company revenues from its affiliates, UNS Gas and UNS Electric, for corporate services provided by TEP, and miscellaneous service-related revenues such as rent on power pole attachments, damage claims, and customer late fees. See Note 3 to the Condensed Consolidated Financial Statements.
Operating Expenses
Generating Output and Fuel and Purchased Power Expense
Total generating output increased during the first quarter of 2015 when compared with the same period last year due to an unplanned maintenance outage in the first quarter of 2014.

25


TEP’s fuel and purchased power expense and energy resources for the quarters ended March 31, 2015 and 2014 are detailed below:
 
Generation and Purchased
Power
 
Fuel and Purchased Power
Expense
 
Three Months Ended March 31,
 
2015
 
2014
 
2015
 
2014
 
Millions of kWh
 
Millions of Dollars
Coal-Fired Generation
1,938

 
2,296

 
$
55

 
$
56

Gas-Fired Generation
448

 
239

 
14

 
11

Utility Owned Renewable Generation
23

 
10

 

 

Fuel Expense for Springerville Units 3 and 4(1)

 

 
2

 
1

Total Generation
2,409

 
2,545

 
71

 
68

Total Purchased Power
789

 
441

 
30

 
22

Transmission and Other PPFAC Recoverable Costs

 

 
5

 
4

Increase (Decrease) to Reflect PPFAC Recovery Treatment

 

 
3

 
(2
)
Subtotal
3,198

 
2,986

 
$
109

 
$
92

Less Line Losses and Company Use
(143
)
 
(169
)
 
 
 
 
Total Energy Sold
3,055

 
2,817

 
 
 
 
(1) 
Springerville Unit 3 and 4 Fuel Expense is reimbursed by Tri-State and SRP.
The table below summarizes average fuel cost per kWh generated or purchased:
 
Three Months Ended March 31,
 
2015
 
2014
 
cents per kWh
Coal
2.81

 
2.42

Gas
3.16

 
4.61

Purchased Power
3.87

 
5.13

All Sources
3.46

 
3.34

O&M
The table below summarizes the items included in O&M expense. Base O&M in the first quarter of 2014 includes merger-related expenses of $1 million.
 
Three Months Ended March 31,
 
2015
 
2014
 
Millions of Dollars
Base O&M (Non-GAAP)(1)
$
62

 
$
64

O&M Recorded in Other Expense

 
(2
)
Reimbursed Expenses Related to Springerville Units 3 and 4(2)
17

 
14

Expenses Related to Customer Funded Renewable Energy and DSM Programs(3)
4

 
5

Total O&M (GAAP)
$
83

 
$
81

(1) 
Base O&M is a non-GAAP financial measure and should not be considered as an alternative to O&M, which is determined in accordance with GAAP. TEP believes that Base O&M, which is O&M less reimbursed expenses and expenses related to customer-funded renewable energy and DSM programs, provides useful information because it represents the fundamental level of operating and maintenance expense related to our core business.
(2) 
Expenses related to Springerville Units 3 and 4 are reimbursed with corresponding amounts recorded in Other Revenue. The Third-Party Owners’ share of expenses related to Springerville Unit 1 is included in Base O&M.
(3) 
These expenses are being collected from customers and the corresponding amounts are recorded in retail revenue.

26


The table below summarizes TEP’s pension and other retiree benefit expenses included in Base O&M:
 
Three Months Ended March 31,
 
2015
 
2014
 
Millions of Dollars
Pension Expense Charged to O&M
$
3

 
$
2

Retiree Benefit Expense Charged to O&M
1

 
1

Total
$
4

 
$
3


FACTORS AFFECTING RESULTS OF OPERATIONS
2013 TEP Rate Order
The 2013 TEP Rate Order, issued by the Arizona Corporation Commission (ACC) and effective July 1, 2013, provided for a non-fuel retail Base Rate increase of $76 million; a 10.0% return on equity, a 5.18% cost of long-term debt, and a 1.42% cost of short term debt, resulting in a weighted average cost of capital of 7.26%.
In addition, there are provisions within the 2013 TEP Rate Order allowing more timely recovery of certain costs through several recovery mechanisms:
The LFCR mechanism allows recovery of certain non-fuel costs related to kWh sales lost due to EE programs and DG.
The Environmental Compliance Adjustor (ECA) mechanism allows recovery of certain capital carrying costs to comply with government-mandated environmental regulations between rate cases.
The DSM and Renewable Energy Standard (RES) surcharges allow for recovery of costs to implement DSM and renewable energy programs that support the ACC's EE Standards.
As required by the 2013 Rate Order, TEP filed a compliance report in July 2014 that outlined its planned purchases of: (i) certain ownership interests in Springerville Unit 1; (ii) 75% of Unit 3 of the Gila River Generating Station (Gila River Unit 3); and (iii) the Springerville Coal Handling Facilities. The report estimated that as a result of these purchases, and the termination of certain lease obligations, TEP's 2014 non-fuel revenue requirement would decline by approximately $36 million. However, when other changes to TEP's rate base, expenses and retail sales levels were considered, TEP estimated a non-fuel revenue deficiency of approximately $26 million as of December 31, 2014.
See Note 2 to the Condensed Consolidated Financial Statements for more information.
See Generating Resources and Springerville Coal Handling Facilities Capital Lease Purchase Commitment, below, for more information.
On February 3, 2015, TEP filed a request with the ACC to revise its net metering rates. TEP is proposing a new net metering tariff to ensure that customers who install new rooftop solar power systems pay a more equitable portion of the costs incurred to provide their electric service while still enjoying significant bill savings. TEP is proposing to purchase excess solar output from new rooftop systems at the same price it pays for energy from large local solar arrays rather than providing distributed generation customers with a full retail rate credit.
Generating Resources
At March 31, 2015, approximately 54% of TEP's generating capacity was fueled by coal (Sundt Unit 4 can also be run on natural gas, resulting in 36 MW of additional generating capacity). Existing and proposed federal environmental regulations, as well as potential changes in state regulation, may increase the cost of operating coal-fired generating facilities. TEP is executing coal reduction strategies and evaluating additional steps for reducing the proportion of coal in its fuel mix. TEP's ability to reduce its coal-fired generating capacity will depend on several factors, including, but not limited to:
Regulatory approvals associated with the anticipated closure of San Juan Unit 2, and pending ownership restructuring of the remaining units, see Part II, Item. 5 - Other Information, Environmental Matters;
The outcome of the proposed Clean Power Plan, see Part II, Item. 5 - Other Information, Environmental Matters;
TEP's option to permanently convert Sundt Unit 4 to be fueled by natural gas, see Part II, Item. 5 - Other Information, Environmental Matters;

27


The ability to resolve Springerville Unit 1 legal proceedings relating to the Third Party Owners, see Note 5 to the Condensed Consolidated Financial Statements.
Springerville Unit 1
TEP leased Unit 1 of the Springerville Generating Station and an undivided one-half interest in certain Springerville Common Facilities (collectively Springerville Unit 1) under seven separate lease agreements (Springerville Unit 1 Leases) that were accounted for as capital leases. The leases expired in January 2015. At that time, TEP purchased a leased interest comprising 24.8% of Springerville Unit 1, representing 96 MW of capacity, for an aggregate purchase price of $46 million. Following this purchase, TEP owns 49.5% of Springerville Unit 1, or 192 MW of capacity.
The remaining 50.5% of Springerville Unit 1, or 195 MW of capacity, is owned by third parties. TEP is not obligated to purchase any of the Third-Party Owners’ generating output. TEP is obligated to operate the unit for the Third-Party Owners. The Third-Party Owners are obligated to compensate TEP for their pro rata share of expenses for the unit in the amount of approximately $2 million per month, and their share of capital expenditures, which are expected to be approximately $8 million in 2015.
As of March 31, 2015, TEP has billed the Third-Party Owners approximately $6 million for their pro-rata share of Springerville Unit 1 expenses and less than $0.5 million for their pro-rata share of capital costs, none of which has been paid as of May 4, 2015. On April 20, 2015, TEP filed a demand for arbitration seeking an award of the Third-Party Owners share of unreimbursed expense and capital expenditures for Springerville Unit 1.
See Note 5 to the Condensed Consolidated Financial Statements for a description of legal proceedings relating to the Third-Party Owners.
Gila River Generating Station Unit 3
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). TEP’s interest in Gila River Unit 3 replaces the expired coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2 and is a key component in TEP's strategy to diversify its generation fuel mix.
Potential Plant Retirements
TEP periodically files an Integrated Resource Plan (IRP) with the ACC. The IRP provides a view of forecasted energy needs over a long term (15 years) and options being considered to meet those needs. TEP's 2014 IRP reflected plans to reduce its overall coal capacity by 492 MW (32% of TEP's existing coal fleet) over the next five years at the Springerville, San Juan, and Sundt Generating Stations. In April 2015, the ACC issued an order to acknowledge TEP's 2014 IRP. TEP's planning assumptions included potentially retiring certain coal-fired generating facilities at San Juan and coal handling facilities at Sundt earlier than their current estimated useful lives. These facilities currently do not have the requisite emission control equipment to meet proposed EPA regulations. TEP continues to evaluate the potential need to retire these coal-fired generating facilities earlier than the current estimated useful lives, and plans to seek regulatory recovery for amounts that would not be otherwise recovered if and when any assets are retired. See Part II, Item 5. Other Information, Environmental Matters.
Springerville Coal Handling Facilities Capital Lease Purchase Commitment
TEP leased interests in the coal handling facilities at the Springerville Generating Station (Springerville Coal Handling Facilities) under two separate lease agreements (Springerville Coal Handling Facilities Leases). The lease agreements had an initial term that expired in April 2015 and provided TEP the option to renew the leases or to purchase the leased interests at the aggregate fixed price of $120 million. In April 2015, TEP exercised its option to purchase the facilities.
Upon the expiration of the lease term, TEP purchased an 86.7% undivided ownership interest in the Springerville Coal Handling Facilities bringing TEP's total ownership interest to 100%. With the completion of the purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to: 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities. TEP expects SRP to complete its purchase commitment in the second quarter 2015. At March 31, 2015, no amounts have been recorded on TEP's balance sheet for commitments from either SRP or Tri-State.

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Springerville Units 3 and 4
TEP receives annual benefits in the form of rental payments and other fees and cost savings from operating Springerville Unit 3 on behalf of Tri-State and Unit 4 on behalf of SRP.
The table below summarizes the income statement line items in which TEP records revenues and expenses related to Springerville Units 3 and 4:
 
Three Months Ended March 31,
 
2015
 
2014
 
Millions of Dollars
Other Revenues
$
24

 
$
21

Fuel Expense
(2
)
 
(1
)
O&M Expense
(17
)
 
(14
)
Interest Rates
See Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Fair Value Measurements
See Note 7 to the Condensed Consolidated Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Cash flows may vary during the year with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of seasonal cash flow, TEP will use its revolving credit facility, as needed, to fund its business activities.
The table below presents net cash provided by (used for) operating, investing and financing activities:
 
Three Months Ended March 31,
 
2015
 
2014
 
Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)
$
67

 
$
65

Net Cash Flows – Investing Activities (GAAP)
(150
)
 
(70
)
Net Cash Flows – Financing Activities (GAAP)
74

 
68

Net Increase (Decrease) in Cash
(9
)
 
63

Beginning Cash
74

 
25

Ending Cash
$
65

 
$
88

The table below shows TEP's net cash flows after capital expenditures and payments on capital lease obligations:
 
Three Months Ended March 31,
 
2015
 
2014
 
Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)
$
67

 
$
65

Less: Capital Expenditures(1)
(145
)
 
(73
)
Net Cash Flows after Capital Expenditures (Non-GAAP)(2)
(78
)
 
(8
)
Less: Payments of Capital Lease Obligations
(8
)
 
(80
)
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations (Non-GAAP)(2)
$
(86
)
 
$
(88
)
(1) 
Includes $46 million related to the purchase of undivided interests in Springerville Unit 1 in January 2015, separately presented on the Statement of Cash Flows.

29


(2) 
Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations, both non-GAAP measures of liquidity, should not be considered as alternatives to Net Cash Flows—Operating Activities, which is determined in accordance with GAAP. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations provide useful information as measures of TEP’s ability to fund capital requirements, make required payments on capital lease obligations, and pay dividends to UNS Energy before consideration of financing activities.
Liquidity Outlook
We believe that we have sufficient liquidity under our revolving credit facilities to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. TEP issued long-term debt in February 2015 to repay revolving and term loans under its credit agreements and to pay a portion of the purchase price for interests in the Springerville Coal Handling Facilities. See Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Operating Activities
In the first three months of 2015, net cash flows from operating activities were $2 million higher than in the same period last year. The increase primarily relates to a $2 million decrease in interest paid, net of amounts capitalized compared with the same period last year.
Investing Activities
Net cash flows used for investing activities increased by $80 million in the first three months of 2015 compared with the same period last year due primarily to a $46 million increase in capital expenditures to purchase an additional 24.8% interests in Springerville Unit 1 for a total ownership interest of 49.5%. Cash flows from investing activities in the first three months of 2015 also included a $27 million increase in capital expenditures to fund system reinforcement through replacements and betterments, primarily the Pinal Central to Tortolita 500kV transmission Line.
Financing Activities
In the first three months of 2015, net cash from financing activities was $6 million higher than the same period last year due to: an increase of $150 million in proceeds from the issuance of long-term debt; the repayment of $130 million in long-term debt; and an $85 million decrease in borrowings (net of repayments) under TEP's revolving credit facilities. Cash flows from financing activities in the first three months of 2015 also reflects a $71 million decrease in payments of capital lease obligations due to the purchase of the remaining undivided interests in Springerville Unit 1.
2015 Unsecured Bond Issuance
In February 2015, TEP issued and sold $300 million of unsecured notes. The bonds bear interest at a fixed rate of 3.05%, and mature in March 2025. TEP may redeem the notes prior to December 15, 2024, with a make-whole premium plus accrued interest. On or after December 15, 2024, TEP may redeem the notes at par plus accrued interest.
In March 2015, TEP used the net proceeds from the sale to repay $215 million of revolving and term loans under its 2014 Credit Agreement and 2010 Credit Agreement. See Credit and Debt Agreements below. In April 2015, TEP used the remaining amount to pay a portion of the purchase price for interest in the Springerville Coal Handling Facilities. See Note 4 to the Condensed Consolidated Financial Statements.

30


Credit and Debt Agreements
 
 
 
At March 31, 2015
 
As of
May 4, 2015
 
Expires
 
Facility Size
 
LOC
Outstanding
 
Borrowings
 
Available Balance
 
Available Balance
 
 
 
Millions of Dollars
2014 Credit Agreement(1)
November
2015
 
 
 
 
 
 
 
 
 
 
Revolving Credit Facility
 
 
70

 

 

 
70

 

2010 Credit Agreement(2)
November
2016
 
 
 
 
 
 
 
 
 
 
Revolving Credit and LOC Facility
 
 
200

 

 

 
200

 
142

LOC Facility
 
 
82

 
82

 

 

 

Reimbursement Agreement(3)
February
2019
 
 
 
 
 
 
 
 
 
 
LOC Facility
 
 
37

 
37

 

 

 

(1) 
In January 2015, amounts borrowed under the term loan commitment were used to purchase existing Pima County, Arizona unsecured tax-exempt industrial development revenue bonds (IDBs) issued in June 2008 for the benefit of TEP in the amount of $130 million. See Note 4 to the Condensed Consolidated Financial Statements. In March 2015, the $130 million term loan portion of the 2014 Credit Agreement was repaid and cannot be reborrowed.
(2) 
Interest rates and fees under the 2010 Credit Agreement, TEP’s core credit facility, are based on a pricing grid tied to TEP’s credit ratings. In February 2015, Moody's Investors Service, Inc. (Moody's) upgraded the senior unsecured and issuer rating of TEP to A3 from Baa1. The interest rate currently in effect on borrowings is LIBOR plus 1.00% for Eurodollar loans or Alternate Base Rate plus 0.00% for Alternate Base Rate loans. The margin rate currently in effect on the $82 million Letter of Credit (LOC) facility is 1.00%. See Note 4 to the Condensed Consolidated Financial Statements.
(3) 
The LOC supports variable rate tax-exempt pollution control bonds and includes fees payable on the aggregate outstanding amount. The rate currently in effect after Moody's credit upgrade in February 2015 is 0.75% per annum.
Restrictive Debt Covenants
Certain of TEP's credit and debt agreements contain pricing based on TEP’s credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP pays on its borrowings and the amount of fees it pays for its LOCs and unused commitments. A downgrade in TEP’s credit ratings would not cause a restriction in TEP’s ability to borrow under its revolving credit facilities.
The agreements contain restrictions on mergers and sales of assets as well as a maximum leverage test. TEP can pay dividends if it maintains compliance with these restrictions as well as those of the Merger order. The agreements also include conditions of default that would entitle the lenders to accelerate the maturity of all amounts outstanding. At March 31, 2015, TEP was in compliance with all covenants related to its credit agreements and the terms of the Merger order. See Note 4 to the Condensed Consolidated Financial Statements.
Capital Lease Obligations
At March 31, 2015, TEP had $191 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease obligations:
 
Capital Lease Obligation
Balance As Of
 
 
 
 
Capital Leases(1)
March 31, 2015
 
Expiration
 
Renewal/Purchase Option
 
Millions of Dollars
 
 
 
 
Springerville Coal Handling Facilities(2)
$
117

 
April 2015
 
Fixed price purchase
option of $120 million
Springerville Common Facilities(3)
74

 
2017 and 2021
 
Fixed price purchase
option of $106 million
Total Capital Lease Obligations
$
191

 
 
 
 
 
(1) 
In January 2015, the Springerville Unit 1 leases expired and TEP purchased additional undivided interests in the facility. At March 31, 2015 there is no capital lease obligation balance related to Springerville Unit 1.

31


(2) 
The $117 million balance includes the present value at the date of the commitment for the lease purchase options elected in April 2014. In April 2015, the purchase of Springerville Coal Handling Facilities was completed.
(3) 
The Springerville Common Facilities Leases cover an undivided one-half interest in certain Springerville Common Facilities.
TEP's capital lease obligation balances decline over time due to the normal capital lease payments made by TEP.
Contractual Obligations
There have been no changes in TEP's contractual obligations or other commercial commitments from those reported in our 2014 Annual Report on Form 10-K, other than the following changes in 2015:
In February 2015, TEP issued and sold $300 million aggregate principal amount of its senior unsecured notes bearing interest at the fixed rate of 3.05% and maturing March 15, 2025. See Note 4 to the Condensed Consolidated Financial Statements.
In March 2015, TEP repaid the $130 million term loan under the December 2014 Credit Agreement. See Note 4 to the Condensed Consolidated Financial Statements.
In April 2015, upon the expiration of the lease term, TEP purchased its undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million. With the completion of TEP's purchase, SRP has an obligation to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million. TEP expects SRP to complete its purchase commitment in the second quarter of 2015. Tri-State does not have an obligation to purchase the facilities, but by April 2016 Tri-State must elect to either 1) buy a portion of the facilities for $24 million or 2) continue to make payments to TEP for the use of the facilities. See Factors Affecting Results of Operations, Springerville Coal Handling Facilities Capital Lease Purchase Commitment and Note 4 to the Condensed Consolidated Financial Statements.
TEP entered into new forward purchased power commitments with minimum payment obligations of $30 million in 2015 and $11 million in 2016. See Note 5 to the Condensed Consolidated Financial Statements.
TEP entered into a new gas transportation commitment with minimum payment obligations of $1 million in 2015, $2 million in each of 2016 through 2019, and $47 million in total thereafter through 2039. See Note 5 to the Condensed Consolidated Financial Statements.
We have reviewed our contractual obligations and provide the following additional information:
TEP conducts its wholesale marketing and risk management activities under certain master agreements whereby TEP may be required to post credit enhancements in the form of cash or an LOC due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, a change in TEP’s credit ratings, or if there has been a material change in TEP’s creditworthiness. As of March 31, 2015, TEP had posted less than $1 million in LOCs as collateral with wholesale counterparties for credit enhancement.
We do not have any provisions in any of our debt or lease agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.
Income Tax Position
The 2010 Federal Tax Relief Act, the American Taxpayer Relief Act of 2012, and the Tax Increase Prevention Act of 2014 include provisions that make qualified property placed in service between 2010 and 2014 eligible for bonus depreciation for tax purposes. In addition, the IRS issued new guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions are an acceleration of tax benefits TEP otherwise would have received over 20 years and have created net operating loss carryforwards that can be used to offset future taxable income. As a result, TEP did not pay any federal or state income taxes the first three months of 2015 and does not expect to make any payments until 2019.
Dividends on Common Stock
TEP did not pay dividends to UNS Energy in the first three months of 2015 or 2014.


32


CRITICAL ACCOUNTING POLICIES
There have been no significant changes in our accounting policies from those disclosed in our 2014 Annual Report on Form 10-K.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. The revenue standard requires entities to apply the guidance retrospectively or recognize the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings supplemented by additional disclosures. On April 1, 2015, the FASB proposed to defer the effective date of the revenue recognition standard by one year. Based on the proposed effective date, we will be required to adopt the new guidance for annual and interim periods beginning January 1, 2018; early adoption is permitted for annual and interim periods beginning January 1, 2017. We are in the process of identifying contracts with customers and performance obligations in contracts.
In June 2014, the FASB issued guidance that requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. An entity can elect to adopt the amendment prospectively or retrospectively. TEP does not expect the adoption of this guidance to have a material impact on our disclosures, financial condition, results of operations, or cash flows.
In August 2014, the FASB issued guidance about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and provide related disclosures. This update is effective for annual and interim periods beginning January 1, 2017; early adoption is permitted. TEP does not expect the adoption of this guidance to have an impact on its disclosures.
In January 2015, the FASB issued an accounting standards update that removes the concept of extraordinary items from U.S. GAAP. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. TEP does not expect the adoption of this guidance to impact its results of operations or disclosures.
In February 2015, the FASB issued guidance that amends the current consolidation guidance; the amendment affects both the variable interest entity and voting interest entity consolidation models. This standard is effective beginning January 1, 2016; early adoption is permitted. We are evaluating the impact to our financial statements and disclosures.
In April 2015, the FASB issued guidance which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, rather than as deferred charges. The amendment is effective for periods beginning January 1, 2016 and will be applied retrospectively; early adoption is permitted. The adoption of this standard is expected to result in reclassification of debt issuance costs from Other Current Assets and Other Assets to Long-Term Debt on our balance sheet. TEP’s deferred debt issuance costs associated with long-term debt outstanding totaled $12 million at March 31, 2015 and $11 million at December 31, 2014, of which approximately $1 million is classified as current at each date.
In April 2015, the FASB issued guidance that will help entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement either as a software license or a service contract. The standard is effective for periods beginning January 1, 2016; early adoption is permitted. An entity can elect to adopt the amendment prospectively or retrospectively. TEP does not expect the adoption of this guidance to have a material impact on our disclosures, financial condition, results of operations, or cash flows.


33


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
TEP’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. We enter into interest rate swaps and financing transactions to manage changes in interest rates. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms.
There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2014.

ITEM 4. CONTROLS AND PROCEDURES
TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13a – 15(e) or Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or person performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures are effective as of March 31, 2015.
While TEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting, there has been no change in TEP’s internal control over financial reporting during the first quarter of 2015 that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.


34



PART II

ITEM 1. LEGAL PROCEEDINGS
See the legal proceedings described in Item 3. Legal Proceedings in our 2014 Annual Report on Form 10-K and in Note 5 to the Condensed Consolidated Financial Statements and in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, which descriptions in Note 5 and Item 2 are incorporated herein by reference.

ITEM 1A. RISK FACTORS
The business and financial results of TEP are subject to numerous risks and uncertainties. You should carefully consider the risks and uncertainties reported in our 2014 Annual Report on Form 10-K.

ITEM 5. OTHER INFORMATION

RATIO OF EARNINGS TO FIXED CHARGES
The following table reflects the ratio of earnings to fixed charges:
 
Three Months Ended March 31, 2015
 
Twelve Months Ended March 31, 2015
Ratio of Earnings to Fixed Charges
1.541

 
2.574

For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, plus interest expense and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount and expense, interest on operating lease payments, and expense on indebtedness, including capital lease obligations.

ENVIRONMENTAL MATTERS
Environmental Regulation
The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.
National Ambient Air Quality Standards
In November 2014, the EPA released a proposed rule that would revise the ozone National Ambient Air Quality Standards (NAAQS). The proposal revises the primary and secondary 8-hour NAAQS to within a range of 65-70 parts per billion (ppb), but the EPA is also taking comments on retaining the existing 75 ppb 8-hour standard or adopting an 8-hour standard as low as 60 ppb.
If the standard is ultimately revised below 70 ppb, Pima County and many other parts of Arizona would likely not be able to comply based on current ozone levels. Arizona would then need to submit a plan to meet the revised standard which could potentially limit economic growth in the affected regions. TEP filed comments on the proposed rule urging EPA to retain the existing standard at 75 ppb. The EPA is expected to finalize the rule by October 2015.
Hazardous Air Pollutant Requirements
The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In February 2012, the EPA issued final Mercury and Air Toxics Standards (MATS) rules to set

35



the standards for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the final rule, additional emission control equipment would have been required by April 2015. However, TEP, as operator of Springerville and Sundt, and the operator of Navajo have received extensions until April 2016 to comply with the MATS rules.
For more information see Note 5 to the Condensed Consolidated Financial Statements.
Navajo
Based on the MATS rules, Navajo will require mercury control equipment by April 2016. TEP’s share of the estimated capital costs of this equipment is $1 million for mercury control. TEP expects its share of the annual operating costs for mercury control to be $1 million.
San Juan
TEP expects San Juan’s current emission controls to be adequate to comply with the MATS rules.
Four Corners
TEP expects Four Corners' current emission controls to be adequate to comply with the MATS rules.
Springerville Generating Station
Based on the MATS rules, Springerville may require mercury emission control equipment by April 2016. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $1 million. Estimated costs are 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. With the completion of the purchases, Third-Party Owners are responsible for 50.5% of environmental costs attributed to Springerville Unit 1. TEP continues to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
Sundt Generating Station
TEP expects the MATS rules will have little effect on capital expenditures at Sundt.
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. BART applies to plants built between August 1962 and August 1977. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.
Complying with the EPA’s BART findings, 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 the units they own at these power plants. TEP cannot predict the ultimate outcome of these matters.
For more information see Note 5 to the Condensed Consolidated Financial Statements.
Navajo
In August 2014, the EPA published the final Regional Haze Federal Implementation Plan (FIP) for Navajo. Among other things, the FIP calls for the shut-down of one unit or an equivalent reduction in emissions by 2020. The shutdown of one unit will not impact the total amount of energy delivered to TEP from Navajo. Additionally, the remaining Navajo participants would be required to install Selective Catalytic Reduction (SCR) or an equivalent technology on the remaining two units by 2030, and the current owners have to cease their operation of conventional coal-fired generation at Navajo no later than December 22, 2044. The Navajo Nation can continue operation after 2044 at its election. The final BART includes options that accommodate potential ownership changes at the plant. The plant has until December 2019 to notify the EPA which option will be implemented.
If SCR technology is ultimately implemented at Navajo, TEP estimates its share of the capital cost will be $28 million for the two remaining units. Also, the installation of SCR technology at Navajo could increase the power plant's particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be

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about $28 million for the two remaining units. TEP's share of annual operating costs for SCR and baghouses is estimated at less than $1 million each.
San Juan
In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan. The SIP requires the closure of Units 2 and 3 by December 2017 and the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4 by February of 2016. TEP owns 50% of Units 1 and 2 at San Juan. TEP expects its share of the cost to install SNCR technology on San Juan Unit 1 to be approximately $12 million. Additionally, the SIP approval references a New Source Review permit issued by the New Mexico Environment Department in November 2013 which, among other things, calls for balanced draft upgrades on San Juan Unit 1 to reduce particulate matter emissions. Public Service Company of New Mexico (PNM), the operator of San Juan, is currently installing SNCR and making the necessary balanced draft modifications to San Juan Unit 1. TEP’s share of the balanced draft upgrades is expected to be approximately $25 million for a total of $37 million in capital expenditures. TEP's share of incremental annual operating costs for SNCR for San Juan Unit 1 is estimated at $1 million.
In connection with the implementation of the SIP revision and the early retirement of San Juan Units 2 and 3, some of the San Juan owner participants (Participants) have expressed a desire to exit their ownership in the plant. As a result, the Participants are attempting to negotiate a restructuring of the ownership in San Juan, as well as addressing the obligations of the exiting Participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items. The Participants have engaged a mediator to assist in facilitating the resolution of these matters among the Participants. The Participants of the affected units also may seek approvals of their utility commissions or governing boards. We are unable to predict the outcome of the negotiations and mediation.
Upon the early retirement of San Juan Unit 2, TEP will seek ACC approval to recover any unrecovered cost. TEP's 2013 Rate Case 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. At March 31, 2015, the net book value of TEP's share in San Juan Unit 2 was $109 million.
Four Corners
In 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on one unit by October 2016 and the remaining units by October 2017. In December 2013, Arizona Public Service Company (APS), the operator of Four Corners, decided to exercise an option to shut down Units 1, 2, and 3 and install SCRs on Units 4 and 5. Under this scenario, the installation of SCR technology can be delayed until July 2018. TEP's estimated share of the capital costs to install SCR technology on Units 4 and 5 is approximately $44 million. TEP's share of incremental annual operating costs for SCR is estimated at $2 million.
Springerville
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.
Sundt
In June 2014, the EPA issued a final Regional Haze FIP for Arizona including BART requirements for Sundt. The final FIP would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection (DSI) 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. TEP estimates that the cost to install SNCR and DSI would be approximately $12 million, and the incremental annual operating costs would be $5 million to $6 million. Under the rule, TEP is required to notify the EPA of its decision by March 2017. We expect to make a decision by early 2016 as part of our MATS compliance plan for Sundt. At March 31, 2015, the net book value of the Sundt coal handling facilities was $17 million. If retired early, we will request the ACC's approval to recover all the remaining costs of the coal handling facilities.
Greenhouse Gas Regulation
In June 2013, President Obama directed the EPA to move forward with carbon emission regulations for both new and existing fossil-fueled power plants.

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In January 2014, the EPA published a re-proposed rule for new power plants. At this time, TEP does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on its operations.
In June 2014, the EPA issued proposed carbon emission regulations for existing power plants called the Clean Power Plan. The Clean Power Plan targets a nation-wide reduction in carbon emissions of 30% by 2030. To achieve this goal, the proposed plan sets carbon emission rates for each state that must be achieved by an interim period of 2020-2029, with final emission rates by 2030. States can apply a variety of strategies to achieve the interim and final emission rates. Using 2012 as a baseline year, Arizona's carbon emission rate for 2030 represents a 52% reduction, most of which would be required by the interim emission rate requirement and could lead to the early retirement of coal generation in Arizona by 2020. The EPA expects to issue a final rule by the summer of 2015, and under the current proposal, states must file implementation plans by June 2016 or June 2017 for multi-state plans. In October 2014, the EPA issued a supplemental proposal regarding carbon emissions regulation impacting the Navajo Nation and the Four Corners and Navajo generating stations which are located on land leased from the Navajo Nation. The regulation, if implemented as proposed, will require carbon reductions on the Navajo Reservation; however, the reduction requirement is less than what is anticipated from unit retirements at the Four Corners and Navajo generating stations associated with Regional Haze requirements. See Regional Haze Rules above.
TEP will continue working with federal and state regulatory authorities, other neighboring utilities, and stakeholders to seek relief from the proposed regulation by reducing the disproportionately high level of carbon emissions reduction for Arizona, and to seek relief from the interim and final proposed compliance requirements. On December 1, 2014, UNS Energy submitted comments on the proposal on behalf of TEP and its other utility subsidiaries. The EPA has received over 3.8 million comments in response to the proposed rule. The proposed rule has been challenged in court and is subject to further legal challenge. TEP cannot predict the ultimate outcome of these matters.
Coal Combustion Residuals Regulations
In April 2015, the EPA issued a final rule requiring all coal ash and other coal combustion residuals to be treated as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) while allowing for the continued recycling of coal ash. TEP is in the process of evaluating the final impacts of the rule on our coal fired generation. However, TEP does not anticipate significant impacts to our existing facilities where coal combustion residual are managed. Additional requirements would apply to lateral expansion of those existing landfills or to any new landfill.
For more information see Note 5 to the Condensed Consolidated Financial Statements.

ITEM 6. EXHIBITS
See Exhibit Index.


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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 
 
 
 
TUCSON ELECTRIC POWER COMPANY
 
 
 
(Registrant)
 
 
 
 
Date:
May 5, 2015
 
/s/ Kevin P. Larson
 
 
 
Kevin P. Larson
 
 
 
Senior Vice President and Chief
 
 
 
Financial Officer


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EXHIBIT INDEX
 
 
 
12
 
 
Computation of Ratio of Earnings to Fixed Charges.
 
 
 
31(a)
 
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by David G. Hutchens.
 
 
 
31(b)
 
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Kevin P. Larson.
 
 
 
*32
 
 
Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
 
 
 
101.INS
 
 
XBRL Instance Document
 
 
 
 
 
101.SCH
 
 
XBRL Taxonomy Extension Schema Document
 
 
 
 
 
101.CAL
 
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
 
 
101.LAB
 

 
XBRL Taxonomy Extension Label Linkbase Document
 
 
 
 
 
101.PRE
 

 
XBRL Taxonomy Extension Presentation Linkbase Document

 
 
 
 
 
101.DEF
 

 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
 
 
 
 
*
Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.


40