Document


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 June 30, 2018
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
(Former name, former address and former fiscal year, if changed since last report): N/A

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 o
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 o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer o Accelerated Filer o Non-Accelerated Filer x (Do not check if a smaller reporting company) Smaller Reporting Company o Emerging Growth Company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
All shares of outstanding common stock of Tucson Electric Power Company are held by its parent company, UNS Energy Corporation, which is an indirect, wholly-owned subsidiary of Fortis Inc. There were 32,139,434 shares of common stock, no par value, outstanding as of July 30, 2018.

i



Table of Contents
PART I
 
 
 
 
 
PART II
 
 

ii



DEFINITIONS
The abbreviations and acronyms used in the first six months of 2018 Form 10-Q are defined below:
2010 Reimbursement Agreement
 
Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2017 Rate Order
 
A rate order issued by the ACC resulting in a new rate structure for TEP, effective on February 27, 2017
ACC
 
Arizona Corporation Commission
ACC Refund Order
 
An order issued by the ACC approving TEP’s proposal to return ongoing savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of a customer bill credit and a regulatory liability that reflects the deferral of the return of a portion of the savings
ASU
 
Accounting Standard Update
BART
 
Best Available Retrofit Technology
BBtu
 
Billion British thermal units
DG
 
Distributed Generation
DSM
 
Demand Side Management
EDIT
 
Excess Deferred Income Taxes
EE Standards
 
Energy Efficiency Standards
EPA
 
Environmental Protection Agency
FERC
 
Federal Energy Regulatory Commission
FERC Refund Order
 
An order issued by the FERC directing TEP to either: (i) submit proposed revisions to its stated transmission rates or stated transmission revenue requirements to reflect the change in the federal corporate income tax rate as a result of the TCJA; or (ii) show cause why it should not be required to do so
Fortis
 
Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada, whose principal executive offices are located at Fortis Place, Suite 1100, 5 Springdale Street, St. John's, NL A1E 0E4
Four Corners
 
Four Corners Generating Station
GAAP
 
Generally Accepted Accounting Principles in the United States of America
Gila Acquisition
 
SRP entered into an agreement to acquire Gila River Units 1 and 2 from third-parties
Gila River
 
Gila River Generating Station
GWh
 
Gigawatt-hour(s)
kWh
 
Kilowatt-hour(s)
LFCR
 
Lost Fixed Cost Recovery
LOC
 
Letter(s) of Credit
Luna
 
Luna Generating Station
MW
 
Megawatt(s)
MWh
 
Megawatt-hour(s)
Navajo
 
Navajo Generating Station
NBV
 
Net Book Value
NOI
 
Notice of Inquiry
Phase 2
 
Second phase of TEP's rate case proceedings originally filed November 2015
PPA
 
Power Purchase Agreement
PPFAC
 
Purchased Power and Fuel Adjustment Clause
Regional Haze Rules
 
Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
RES
 
Renewable Energy Standard
Retail Rates
 
Rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment
San Juan
 
San Juan Generating Station
SCR
 
Selective Catalytic Reduction

iii



SES
 
Southwest Energy Solutions, Inc.
Springerville
 
Springerville Generating Station
SRP
 
Salt River Project Agricultural Improvement and Power District
Sundt
 
H. Wilson Sundt Generating Station
TCJA
 
On December 22, 2017, the Tax Cuts and Jobs Act was signed into law enacting significant changes to the Internal Revenue Code including a reduction in the federal corporate income tax rate from 35% to 21% effective for tax years beginning after 2017
TEP
 
Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Tolling PPA
 
A 20-year tolling PPA that TEP entered into in 2017 with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2
TSA
 
Transmission Service Agreement
UNS Electric
 
UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
UNS Energy
 
UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy Affiliates
 
Affiliated subsidiaries of UNS Energy Corporation including UniSource Energy Services, Inc., UNS Electric, Inc., UNS Gas, Inc., and Southwest Energy Solutions, Inc.
UNS Gas
 
UNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
VIE
 
Variable Interest Entity


iv

Table of Contents

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 Company (TEP or the Company) 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 TEP in this Quarterly Report on Form 10-Q. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events, future economic conditions, future operational or financial 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, believes, estimates, expects, intends, may, plans, predicts, potential, projects, would, 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 may otherwise 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 estimates, expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s estimates, 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 I, Item 1A. Risk Factors of our 2017 Form 10-K; Part II, Item 1A. Risk Factors; Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations; and other parts of this report. These factors include: state and federal regulatory and legislative decisions and actions, including changes in tax policies; changes in, and compliance with, environmental laws and regulatory decisions and policies that could increase operating and capital costs, reduce generation facility output or accelerate generation 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 and bank markets; the performance of the stock market and a changing interest rate environment, which affect the value of our pension and other postretirement benefit plan assets and the related contribution requirements and expenses; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting policies and estimates; the ongoing impact of mandated energy efficiency and distributed generation (DG) initiatives; changes to long-term contracts; the cost of fuel and power supplies; the ability to obtain coal from our suppliers; cyber-attacks, data breaches, or other challenges to our information security, including our operations and technology systems; the performance of TEP's generation facilities; and the impact of the Tax Cuts and Jobs Act (TCJA) on our financial condition and results of operations, including the assumptions we make relating thereto.


v

Table of Contents

PART I
ITEM 1. FINANCIAL STATEMENTS
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(Amounts in thousands)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Operating Revenues
$
354,246

 
$
352,144

 
$
629,336

 
$
620,526

 
 
 
 
 
 
 
 
Operating Expenses
 
 
 
 
 
 
 
Fuel
62,870

 
59,744

 
130,893

 
126,472

Purchased Power
32,389

 
43,841

 
52,753

 
68,136

Transmission and Other PPFAC Recoverable Costs
9,909

 
7,983

 
19,700

 
16,882

Increase (Decrease) to Reflect PPFAC Recovery Treatment
13,372

 
(7,417
)
 
5,406

 
(15,607
)
Total Fuel and Purchased Power
118,540

 
104,151

 
208,752

 
195,883

Operations and Maintenance
93,445

 
84,490

 
176,601

 
166,631

Depreciation
39,418

 
38,208

 
78,294

 
76,365

Amortization
6,021

 
5,458

 
12,042

 
10,860

Taxes Other Than Income Taxes
14,299

 
12,980

 
28,479

 
26,780

Total Operating Expenses
271,723

 
245,287

 
504,168

 
476,519

 
 
 
 
 
 
 
 
Operating Income
82,523

 
106,857

 
125,168

 
144,007

 
 
 
 
 
 
 
 
Other Income (Expense)
 
 
 
 
 
 
 
Interest Expense
(16,707
)
 
(16,366
)
 
(33,192
)
 
(32,681
)
Allowance For Borrowed Funds
706

 
590

 
1,393

 
1,120

Allowance For Equity Funds
1,532

 
1,434

 
3,177

 
2,792

Other, Net
1,679

 
579

 
1,255

 
8,307

Total Other Income (Expense)
(12,790
)
 
(13,763
)
 
(27,367
)
 
(20,462
)
 
 
 
 
 
 
 
 
Income Before Income Tax Expense
69,733

 
93,094

 
97,801

 
123,545

Income Tax Expense
12,136

 
32,159

 
16,401

 
41,851

Net Income
$
57,597

 
$
60,935

 
$
81,400

 
$
81,694

The accompanying notes are an integral part of these financial statements.


1


TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in thousands)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Comprehensive Income
 
 
 
 
 
 
 
Net Income
$
57,597

 
$
60,935

 
$
81,400

 
$
81,694

Other Comprehensive Income
 
 
 
 
 
 
 
Net Changes in Fair Value of Cash Flow Hedges:
 
 
 
 
 
 
 
Net of Income Tax Expense of $32 and $59
96

 
96

 
 
 
 
Net of Income Tax Expense of $73 and $133
 
 
 
 
219

 
215

Supplemental Executive Retirement Plan Adjustments:
 
 
 
 
 
 
 
Net of Income Tax Expense of $39 and $43
117

 
70

 
 
 
 
Net of Income Tax Expense of $79 and $86
 
 
 
 
232

 
140

Total Other Comprehensive Income, Net of Tax
213

 
166

 
451

 
355

Total Comprehensive Income
$
57,810

 
$
61,101

 
$
81,851

 
$
82,049

The accompanying notes are an integral part of these financial statements.


2


TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in thousands)
 
Six Months Ended June 30,
 
2018
 
2017
Cash Flows from Operating Activities
 
 
 
Net Income
$
81,400

 
$
81,694

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
Depreciation Expense
78,294

 
76,365

Amortization Expense
12,042

 
10,860

Amortization of Debt Issuance Costs
1,168

 
1,178

Use of Renewable Energy Credits for Compliance
15,132

 
11,245

Deferred Income Taxes
21,924

 
41,855

Pension and Other Postretirement Benefits Expense
7,668

 
8,019

Pension and Other Postretirement Benefits Funding
(5,708
)
 
(5,165
)
Allowance for Equity Funds Used During Construction
(3,177
)
 
(2,792
)
FERC Transmission Refund Payable
—

 
(4,878
)
Changes in Current Assets and Current Liabilities:
 
 
 
Accounts Receivable
(41,534
)
 
(44,596
)
Materials, Supplies, and Fuel Inventory
8,102

 
(4,825
)
Regulatory Assets
(5,008
)
 
(7,217
)
Accounts Payable and Accrued Charges
16,385

 
26,848

Regulatory Liabilities
17,180

 
(10,299
)
Other, Net
(6,081
)
 
(8,370
)
Net Cash Flows—Operating Activities
197,787

 
169,922

Cash Flows from Investing Activities
 
 
 
Capital Expenditures
(174,810
)
 
(151,207
)
Purchase Intangibles, Renewable Energy Credits
(25,848
)
 
(27,330
)
Contributions in Aid of Construction
7,773

 
2,917

Net Cash Flows—Investing Activities
(192,885
)
 
(175,620
)
Cash Flows from Financing Activities
 
 
 
Proceeds from Borrowings, Revolving Credit Facility
66,000

 
15,000

Repayments of Borrowings, Revolving Credit Facility
(93,000
)
 
(15,000
)
Payments of Capital Lease Obligations
(10,930
)
 
(14,463
)
Other, Net
(3
)
 
320

Net Cash Flows—Financing Activities
(37,933
)
 
(14,143
)
Net Decrease in Cash, Cash Equivalents, and Restricted Cash
(33,031
)
 
(19,841
)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period
49,501

 
43,325

Cash, Cash Equivalents, and Restricted Cash, End of Period
$
16,470

 
$
23,484

The accompanying notes are an integral part of these financial statements.

3


TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in thousands, except share data)
 
June 30, 2018
 
December 31, 2017
ASSETS
 
 
 
Utility Plant
 
 
 
Plant in Service
$
5,882,412

 
$
5,780,805

Utility Plant Under Capital Leases
249,871

 
84,870

Construction Work in Progress
190,166

 
160,288

Total Utility Plant
6,322,449

 
6,025,963

Accumulated Depreciation and Amortization
(2,242,099
)
 
(2,193,656
)
Accumulated Amortization of Capital Lease Assets
(67,747
)
 
(63,605
)
Total Utility Plant, Net
4,012,603

 
3,768,702

 
 
 
 
Investments and Other Property
50,589

 
51,260

 
 
 
 
Current Assets
 
 
 
Cash and Cash Equivalents
6,341

 
37,701

Accounts Receivable, Net
179,303

 
137,932

Fuel Inventory
17,139

 
25,059

Materials and Supplies
103,176

 
103,981

Regulatory Assets
111,797

 
93,960

Derivative Instruments
7,015

 
3,187

Other
18,201

 
10,777

Total Current Assets
442,972

 
412,597

Regulatory and Other Assets
 
 
 
Regulatory Assets
306,466

 
293,551

Derivative Instruments
3,773

 
8,826

Other
64,752

 
55,313

Total Regulatory and Other Assets
374,991

 
357,690

Total Assets
$
4,881,155

 
$
4,590,249

The accompanying notes are an integral part of these financial statements.

(Continued)

4


TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in thousands, except share data)
 
June 30, 2018
 
December 31, 2017
CAPITALIZATION AND OTHER LIABILITIES
 
 
 
Capitalization
 
 
 
Common Stock Equity:
 
 
 
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of June 30, 2018 and December 31, 2017)
$
1,296,539

 
$
1,296,539

Capital Stock Expense
(6,357
)
 
(6,357
)
Retained Earnings
462,354

 
380,076

Accumulated Other Comprehensive Loss
(6,653
)
 
(6,226
)
Total Common Stock Equity
1,745,883

 
1,664,032

Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2018 and December 31, 2017)
—

 
—

Capital Lease Obligations
182,630

 
28,519

Long-Term Debt, Net
1,318,398

 
1,354,423

Total Capitalization
3,246,911

 
3,046,974

Current Liabilities
 
 
 
Current Maturities of Long-Term Debt
136,700

 
100,000

Borrowings Under Revolving Credit Facility
8,000

 
35,000

Capital Lease Obligations
10,535

 
10,749

Accounts Payable
116,650

 
97,367

Accrued Taxes Other than Income Taxes
44,783

 
40,706

Accrued Employee Expenses
23,398

 
30,929

Accrued Interest
17,634

 
14,750

Regulatory Liabilities
107,033

 
89,024

Customer Deposits
26,298

 
24,865

Derivative Instruments
23,034

 
10,667

Other
19,556

 
18,119

Total Current Liabilities
533,621

 
472,176

Regulatory and Other Liabilities
 
 
 
Deferred Income Taxes, Net
329,295

 
300,258

Regulatory Liabilities
500,633

 
516,438

Pension and Other Postretirement Benefits
132,457

 
133,799

Derivative Instruments
34,164

 
17,907

Other
104,074

 
102,697

Total Regulatory and Other Liabilities
1,100,623

 
1,071,099

 
 
 
 
Commitments and Contingencies

 

 
 
 
 
Total Capitalization and Other Liabilities
$
4,881,155

 
$
4,590,249

The accompanying notes are an integral part of these financial statements.

(Concluded)


5


TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited)
(Amounts in thousands)
 
Common Stock
 
Capital Stock Expense
 
Retained Earnings
 
Accumulated Other Comprehensive Loss
 
Total Stockholder's Equity
Balances as of December 31, 2016
$
1,296,539

 
$
(6,357
)
 
$
273,408

 
$
(4,555
)
 
$
1,559,035

Net Income
 
 
 
 
81,694

 
 
 
81,694

Other Comprehensive Income, Net of Tax
 
 
 
 
 
 
355

 
355

Balances as of June 30, 2017
$
1,296,539

 
$
(6,357
)
 
$
355,102

 
$
(4,200
)
 
$
1,641,084

 
Common Stock
 
Capital Stock Expense
 
Retained Earnings
 
Accumulated Other Comprehensive Loss
 
Total Stockholder's Equity
Balances as of December 31, 2017
$
1,296,539

 
$
(6,357
)
 
$
380,076

 
$
(6,226
)
 
$
1,664,032

Net Income
 
 
 
 
81,400

 
 
 
81,400

Other Comprehensive Income, Net of Tax
 
 
 
 
 
 
451

 
451

Adoption of ASU, Cumulative Effect Adjustment
 
 
 
 
878

 
(878
)
 
—

Balances as of June 30, 2018
$
1,296,539

 
$
(6,357
)
 
$
462,354

 
$
(6,653
)
 
$
1,745,883

The accompanying notes are an integral part of these financial statements.


6
Table of Contents
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION
TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 424,000 retail 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).
BASIS OF PRESENTATION
TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with Generally Accepted Accounting Principles (GAAP) in the United States of America, including specific accounting guidance for regulated operations and the Securities and Exchange Commission's (SEC) interim reporting requirements.
The Condensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parent and subsidiaries are combined and intercompany balances and transactions are eliminated. TEP jointly owns several generation and transmission facilities with both affiliated and non-affiliated entities. TEP's proportionate share of jointly-owned facilities is recorded in Utility Plant on the Condensed Consolidated Balance Sheets, and its 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 and should be read in conjunction with the Consolidated Financial Statements and footnotes in TEP's 2017 Annual Report on Form 10-K.
The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results.
Certain amounts from prior periods have been reclassified to conform to the current period presentation. Most notably, TEP combined captions on the Condensed Consolidated Statements of Income by reclassifying similar line items into a single line item as follows:
 
As Filed
 
Amount Reclassified
 
As Reclassified
 
As Filed
 
Amount Reclassified
 
As Reclassified
(in thousands)
Three Months Ended June 30, 2017
 
Six Months Ended June 30, 2017
Other Income (Deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest Income
$
433

 
$
(433
)
 
$
—

 
$
526

 
$
(526
)
 
$
—

Other Income
1,872

 
(1,872
)
 
—

 
10,892

 
(10,892
)
 
—

Other Expense
(776
)
 
776

 
—

 
(1,537
)
 
1,537

 
—

Appreciation in Value of Investments
484

 
(484
)
 
—

 
1,218

 
(1,218
)
 
—

Allowance For Equity Funds
—

 
1,434

 
1,434

 
—

 
2,792

 
2,792

Other, Net
—

 
579

 
579

 
—

 
8,307

 
8,307

 
 
 
 
 
 
 
 
 
 
 
 
Interest Expense
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt
15,494

 
(15,494
)
 
—

 
30,930

 
(30,930
)
 
—

Capital Leases
664

 
(664
)
 
—

 
1,328

 
(1,328
)
 
—

Other Interest Expense
208

 
(208
)
 
—

 
423

 
(423
)
 
—

Interest Capitalized
(590
)
 
590

 
—

 
(1,120
)
 
1,120

 
—

Allowance For Borrowed Funds
—

 
(590
)
 
(590
)
 
—

 
(1,120
)
 
(1,120
)
Interest Expense
—

 
16,366

 
16,366

 
—

 
32,681

 
32,681

Variable Interest Entities
TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE), and if it is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holder has: (i) the power to direct activities that most significantly impact the economic performance of the VIE; and (ii) the obligation to absorb losses or the right to receive benefits that could potentially be significant to the VIE.

7
Table of Contents
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



TEP routinely enters into long-term renewable Power Purchase Agreements (PPA) with various entities. Some of these entities are VIEs due to the long-term fixed price component in the agreements. These PPAs effectively transfer commodity price risk to TEP, the buyer of the power, creating a variable interest. TEP has determined it is not a primary beneficiary of the VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.
As of June 30, 2018, the carrying amount of assets and liabilities in the balance sheet that relates to variable interests under long-term PPAs is predominantly related to working capital accounts and generally represents the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.
Restricted Cash
Restricted cash includes cash balances restricted regarding withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement:
 
Six Months Ended June 30,
(in millions)
2018
 
2017
Cash and Cash Equivalents
$
6

 
$
15

Restricted Cash included in:
 
 
 
Investments and Other Property
9

 
7

Current Assets—Other
1

 
1

Total Cash, Cash Equivalents, and Restricted Cash
$
16

 
$
23

Restricted cash included in Investments and Other Property on the Condensed Consolidated Balance Sheets represents cash contractually required to be set aside to pay TEP's share of mine reclamation costs at San Juan Generating Station (San Juan). Restricted cash included in Current Assets—Other represents cash required to be set aside by various contractual agreements.
RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
Revenue from Contracts with Customers
Effective January 1, 2018, TEP adopted accounting guidance that requires recognition of revenue when a customer obtains control of promised goods or services in an amount that reflects the consideration to which the company expects to be entitled. The Company continues to recognize revenue for tariff-based sales to retail and wholesale customers, which represent TEP’s primary source of revenue, as power is delivered. TEP adopted the new guidance using the modified retrospective approach. There was no adjustment identified or recorded to the opening balance of retained earnings on adoption. The Company applied the new revenue guidance to contracts with customers that were not completed at the date of initial application, January 1, 2018. The new guidance requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. See Note 3 for additional disclosure related to TEP's operating revenues.
Compensation—Retirement Benefits
Effective January 1, 2018, TEP adopted accounting guidance that requires an employer to disaggregate the service cost component from the other components of net periodic benefit cost. TEP no longer capitalizes the non-service cost components of net periodic benefit cost as part of inventory or plant in service and presents non-service costs in Other, Net on the Condensed Consolidated Statements of Income. The adoption of this change in accounting principle did not have a material impact on TEP's financial position or results of operations.
Derivatives and Hedging
Effective January 1, 2018, TEP early adopted accounting guidance that simplifies the application of hedge accounting through changes to both the designation and measurement guidance and is intended to enable the Company to better portray the economics of its risk management activities in its financial statements. The adoption of this change in accounting principle had minimal impact to TEP's financial statements and disclosures.

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Reclassification of Certain Tax Effects
Effective January 1, 2018, TEP early adopted accounting guidance that permits reclassification of certain tax effects resulting from the TCJA from accumulated other comprehensive income to retained earnings. TEP applied the guidance as of the beginning of the period of adoption. On adoption, TEP recorded a one-time reclassification of $1 million from Accumulated Other Comprehensive Loss to Retained Earnings on the Condensed Consolidated Balance Sheets as a result of income tax effects due to the reduction in the U.S. federal statutory tax rate. See Note 11 for additional disclosure related to the TCJA.

NOTE 2. REGULATORY MATTERS
The Arizona Corporation Commission (ACC) and the Federal Energy Regulatory Commission (FERC) each regulate portions of 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.
2017 RATE ORDER
Provisions of the 2017 Rate Order, which were effective February 27, 2017, include, but are not limited to:
•
a non-fuel base rate increase of $81.5 million; and
•
adoption of TEP's proposed depreciation and amortization rates, which included a reduction in the depreciable life for San Juan Unit 1.
The ACC deferred matters related to net metering and rate design for new DG customers to a second phase of TEP’s rate case (Phase 2), which is expected to be completed by the end of 2018. TEP cannot predict the outcome of these proceedings.
FEDERAL TAX LEGISLATION
Arizona Corporation Commission
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the ongoing benefits of the TCJA through to customers. In April 2018, the ACC approved TEP’s proposal (ACC Refund Order) to return the ongoing savings from the Company’s federal income tax reduction under the TCJA to its customers through a combination of a customer bill credit and a regulatory liability that reflects the deferral of a portion of the savings to be returned to customers in TEP's next rate case. The ACC Refund Order was effective May 1, 2018.
As a result of the ACC Refund Order, the Company will use a bill credit in 2018 to refund to customers: (i) $27.5 million related to the reduction in the federal corporate income tax rate; and (ii) $9 million related to an estimate of Excess Deferred Income Taxes (EDIT) amortization. TEP will continue to return savings to customers, per the ACC Refund Order, through a combination of a bill credit and a regulatory liability in 2019 and through the completion of its next rate case. The customer bill credit will be trued-up annually to reflect actual kilowatt-hour (kWh) sales and actual EDIT amortization. The regulatory liability will accrue interest and be returned to customers as part of TEP's next rate case. TEP recognized a reduction in Operating Revenues on the Condensed Consolidated Statements of Income of $9 million and $17 million in the three and six months ended June 30, 2018, respectively. TEP's regulatory liability balance related to the ACC Refund Order was $5 million as of June 30, 2018. See Note 11 for additional information regarding the TCJA.
Federal Energy Regulatory Commission
In March 2018, the FERC issued an order directing TEP to either: (i) submit proposed revisions to its stated transmission rates or stated transmission revenue requirements to reflect the change in the federal corporate income tax rate as a result of the TCJA; or (ii) show cause why it should not be required to do so (FERC Refund Order). In May 2018, TEP responded to the order and proposed an overall transmission rate reduction of approximately 5.3%, reflecting the lower federal tax rate, to be effective March 21, 2018. The related revenue subject to refund recorded in the three and six months ended June 30, 2018, did not have a material impact on TEP's financial position or results of operations. TEP cannot predict the outcome of the order.
Also in March 2018, the FERC issued a Notice of Inquiry (NOI) regarding the effect of the TCJA. The NOI seeks comments on a number of issues including how to reflect the amortization of the EDIT regulatory liability balances in rates. TEP cannot predict the impact of the NOI.

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See Note 11 for additional information regarding the TCJA.
COST RECOVERY MECHANISMS
TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.
Purchased Power and Fuel Adjustment Clause
TEP's Purchased Power and Fuel Adjustment Clause (PPFAC) rate is adjusted annually each April 1st and goes into effect for the subsequent 12-month period unless modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment (Retail Rates); and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period. The PPFAC bank balance was over-collected by $18 million as of June 30, 2018, and by $9 million as of December 31, 2017.
The table below presents TEP's PPFAC rates approved by the ACC:
Period
 
Cents per kWh
May 2018 through March 2019
 
0.20

March 2017 through April 2018 (1)
 
(0.20
)
May 2016 through February 2017
 
0.15

(1) 
In February 2017, the ACC approved a PPFAC credit to begin returning the over-collected PPFAC bank balance to customers until the effective date of the 2018 PPFAC rate.
Renewable Energy Standard
The ACC’s Renewable Energy Standard (RES) requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirements by 2025, with DG accounting for 30% of the annual renewable energy requirement. Arizona utilities are required to file an annual RES implementation plan for review and approval by the ACC.
In January 2018, the ACC approved TEP's 2018 RES implementation plan with a budget amount of $54 million, which is recovered through the RES surcharge. The recovery funds the following: (i) the above market cost of renewable power purchases; (ii) previously awarded performance-based incentives for customer-installed DG; and (iii) various other program costs.
Energy Efficiency Standards
TEP is required to implement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency Standards (EE Standards). The EE Standards provide regulated utilities a DSM surcharge to recover from retail customers the costs to implement DSM programs, as well as an annual performance incentive. Energy savings realized through the programs count toward meeting the EE Standards and the associated lost revenue are partially recovered through the Lost Fixed Cost Recovery (LFCR) mechanism.
TEP earns the DSM performance incentive by meeting objectives stated in its energy efficiency implementation plan. The Company records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million in 2018 and 2017 related to performance in Operating Revenues on the Condensed Consolidated Statements of Income.
In August 2017, TEP submitted its application for the 2018 energy efficiency implementation plan with a budget of $23 million and requested a waiver of the 2018 EE Standard. TEP expects to receive a decision on its 2018 energy efficiency implementation plan by the end of 2018.
Lost Fixed Cost Recovery Mechanism
The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer-installed DG. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardless of when the lost retail kWh sales occur. TEP is required to make an annual filing with the ACC requesting recovery of the LFCR revenues recognized in the

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prior year. The recovery is subject to a year-over-year cap of 2% of TEP's applicable retail revenues, as approved in the 2017 Rate Order.
TEP recorded regulatory assets and recognized LFCR revenues of $5 million and $13 million in the three and six months ended June 30, 2018, respectively, and $5 million and $11 million in the three and six months ended June 30, 2017, respectively. LFCR revenues are included in Operating Revenues on the Condensed Consolidated Statements of Income.
REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities recorded in the balance sheet are summarized in the table below:
($ in millions)
Remaining Recovery Period
(years)
 
June 30, 2018
 
December 31, 2017
Regulatory Assets
 
 
 
 
 
Pension and Other Postretirement Benefits
Various
 
$
122

 
$
126

Early Generation Retirement Costs (1)
Various
 
78

 
84

Derivatives
3
 
51

 
18

Income Taxes Recoverable through Future Rates
Various
 
40

 
40

Final Mine Reclamation and Retiree Healthcare Costs (2)
19
 
34

 
31

Lost Fixed Cost Recovery
2
 
33

 
29

Property Tax Deferrals
1
 
25

 
24

Springerville Unit 1 Leasehold Improvements (3)
5
 
13

 
14

Other Regulatory Assets
Various
 
22

 
22

Total Regulatory Assets
 
 
418

 
388

Less Current Portion
1
 
112

 
94

Total Non-Current Regulatory Assets
 
 
$
306

 
$
294

Regulatory Liabilities
 
 
 
 
 
Income Taxes Payable through Future Rates (4)
Various
 
$
349

 
$
353

Net Cost of Removal (5)
Various
 
172

 
180

Renewable Energy Standard
Various
 
49

 
44

Purchased Power and Fuel Adjustment Clause
1
 
18

 
9

Deferred Investment Tax Credits
Various
 
11

 
14

Other Regulatory Liabilities
Various
 
9

 
5

Total Regulatory Liabilities
 
 
608

 
605

Less Current Portion
1
 
107

 
89

Total Non-Current Regulatory Liabilities
 
 
$
501

 
$
516

(1) 
Includes the net book value (NBV) and other related costs of Navajo Generating Station (Navajo) and H. Wilson Sundt Generating Station (Sundt) Units 1 and 2 reclassified from Utility Plant, Net on the Condensed Consolidated Balance Sheets due to the planned early retirement of the facilities. Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030.
(2) 
Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners Generating Station (Four Corners), and Navajo. TEP recognizes these costs at future value and is permitted to recover these costs on a pay-as-you-go basis through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2037.
(3) 
Represents investments TEP made, which were previously recorded in Plant in Service on the Condensed Consolidated Balance Sheets, to ensure that the facilities continued to provide service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Generating Station (Springerville) Unit 1 over a 10-year amortization period.
(4) 
Includes balances related to EDIT as a result of the revaluation of deferred income taxes in 2017 due to the TCJA. TEP is amortizing the EDIT balances in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining life of the related asset. In April 2018, the ACC Refund Order was approved requiring TEP to return EDIT amortization of the ACC-jurisdictional assets with customers. See Note 11 for additional information regarding the TCJA.

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(5) 
Represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, and generation plant and general and intangible plant which are not yet expended.
Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs and Income Taxes Payable through Future Rates related to the EDIT balances, TEP does not pay a return on regulatory liabilities.
FERC COMPLIANCE
In 2016, the FERC issued orders relating to certain late-filed transmission service agreements (TSAs), which resulted in TEP paying time-value refunds to the counterparties of these TSAs. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement resulting in the counterparty paying TEP $8 million. The settlement amount was recorded in Other, Net on the Condensed Consolidated Statements of Income. As a result of the settlement, TEP dismissed a previously filed appeal. In May 2017, the FERC informed TEP that the related investigation was closed. As management no longer believed a loss was probable, TEP reversed the $5 million remaining balance related to potential time-value refunds in Current Liabilities—Other on the Condensed Consolidated Balance Sheets, offsetting Operating Revenues on the Condensed Consolidated Statements of Income.

NOTE 3. REVENUE
TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. Most of the Company's contracts have a single performance obligation, the delivery of power. TEP satisfies the performance obligation over time as power is delivered and control is transferred to the customer. The Company bills for power sales based on the reading of electric meters on a systematic basis throughout the month. In general, TEP's contracts have payment terms of 10 to 20 days from the date the bill is rendered. TEP considers any payment not received by the due date delinquent and charges the customer a late payment fee. No component of the transaction price is allocated to unsatisfied performance obligations.
TEP has certain contracts with variable transaction pricing that require it to estimate the resulting variable consideration. TEP's variable consideration includes revenues that are subject to refund and performance incentive revenues. TEP estimates variable consideration at the most likely amount to which the Company expects to be entitled and recognizes a refund liability until TEP is certain that the Company will be entitled to the consideration. The Company includes estimated amounts of variable consideration in the transaction price to the extent it is probable that changes in its estimate will not result in significant reversals of revenue in subsequent periods.
DISAGGREGATION OF REVENUES
The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in millions)
2018
 
2017
 
2018
 
2017
Retail
$
273

 
$
275

 
$
465

 
$
467

Wholesale
35

 
37

 
73

 
72

Other Services
27

 
23

 
50

 
44

Revenues from Contracts with Customers
335

 
335

 
588

 
583

Alternative Revenues
5

 
5

 
15

 
13

Other
14

 
12

 
26

 
25

Total Operating Revenues
$
354

 
$
352

 
$
629

 
$
621

Retail Revenues
TEP’s tariff-based sales to residential, commercial, and industrial customers are regulated by the ACC and recognized when power is delivered at the amount of consideration that the Company expects to receive in exchange. Retail Revenues include an estimate for unbilled revenues from service that has been provided but not billed by the end of an accounting period. At the end

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



of the month, amounts of power delivered since the last meter reading are estimated and the corresponding unbilled revenue is calculated using anticipated Retail Rates. Unbilled revenues are dependent upon a number of factors that require management’s judgment including estimates of retail sales, customer usage patterns, and pricing. Once the usage is estimated, TEP applies the anticipated rate and records revenue. Unbilled revenues increase during the spring and summer months and decrease during the fall and winter months due to the seasonal fluctuations of TEP’s actual load. The timing of revenue recognition, billings, and cash collections results in billed and unbilled accounts receivable balances on the balance sheet. See Note 4 for components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets.
In January 2018, TEP began to recognize a provision for revenues subject to refund, which reduces operating revenues, and a current regulatory liability for ongoing savings expected to be returned to customers from the Company’s federal income tax reduction under the TCJA. In April 2018, the ACC approved the ACC Refund Order effective May 1, 2018. As a result of the ACC Refund Order, the Company will use a bill credit in 2018 to return savings to customers. See Note 2 for more information regarding the ACC Refund Order.
Wholesale Revenues
TEP’s operations include the wholesale marketing of electricity and transmission to other utilities and power marketers, which may include capacity, power, transmission, and ancillary services. When TEP promises to provide distinct services within a contract, the Company separates the contract into more than one performance obligation. The Company recognizes revenue for wholesale and transmission sales at FERC-approved rates based on demand (for capacity) or the reading of meters (for power). For contracts with multiple performance obligations, all deliverables are eligible for recognition in the month of production; therefore, it is not necessary to allocate the transaction price among the identified performance obligations.
In March 2018, the FERC issued the FERC Refund Order. In May 2018, TEP responded to the order and proposed an overall transmission rate reduction to be effective March 21, 2018. The related revenue subject to refund recorded did not have a material impact on TEP's financial position or results of operations. TEP cannot predict the outcome of the order. See Note 2 for more information regarding the FERC Refund Order.
Other Services Revenues
Other Services Revenues primarily include management fees for Springerville Unit 3, miscellaneous service-related revenues, and reimbursement of various operating expenses for the use of the Springerville Common Facilities by Springerville Units 3 and 4 and the Springerville Coal Handling Facilities by Springerville Unit 3. As the operating agent for the third-party owner of Springerville Unit 3, TEP may earn an annual incentive or be required to refund its monthly management fee based on unit availability.
Alternative Revenues
Alternative Revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria established by a regulator are met. TEP has identified its LFCR mechanism and DSM performance incentive as alternative revenues. See Note 2 for additional information regarding these cost recovery mechanisms.
Other Revenues
Other Revenues include gains and losses on derivative contracts, late and returned payment finance charges, and lease income. See Note 10 for information regarding derivative instruments.


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NOTE 4. ACCOUNTS RECEIVABLE
The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets:
(in millions)
June 30, 2018
 
December 31, 2017
Customer (1)
$
98

 
$
81

Customer, Unbilled
61

 
39

Due from Affiliates (Note 5)
6

 
7

Other
20

 
16

Allowance for Doubtful Accounts
(6
)
 
(5
)
Accounts Receivable, Net
$
179

 
$
138

(1) 
Includes $4 million as of June 30, 2018 and $9 million as of December 31, 2017, of receivables related to revenue from derivative instruments.

NOTE 5. RELATED PARTY TRANSACTIONS
TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy Affiliates). These transactions include the sale and purchase of power and transmission services, common cost allocations, and the provision of corporate and other labor related services.
The following table presents the components of related party balances included in Accounts Receivable, Net and Accounts Payable on the Condensed Consolidated Balance Sheets:
(in millions)
June 30, 2018
 
December 31, 2017
Receivables from Related Parties
 
 
 
UNS Electric
$
4

 
$
5

UNS Gas
2

 
2

Total Due from Related Parties
$
6

 
$
7

 
 
 
 
Payables to Related Parties
 
 
 
SES
$
2

 
$
3

UNS Energy
—

 
1

UNS Electric
1

 
—

Total Due to Related Parties
$
3

 
$
4


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in millions)
2018
 
2017
 
2018
 
2017
Goods and Services Provided by TEP to Affiliates

 

 
 
 
 
Transmission Revenues, UNS Electric (1)
$
1

 
$
2

 
$
3

 
$
3

Control Area Services, UNS Electric (2)
1

 
1

 
1

 
1

Common Costs, UNS Energy Affiliates (3)
5

 
4

 
9

 
8

 
 
 
 
 
 
 
 
Goods and Services Provided by Affiliates to TEP
 
 
 
 
 
 
 
Supplemental Workforce, SES (4)
4

 
4

 
7

 
7

Corporate Services, UNS Energy (5)
1

 
1

 
3

 
3

Corporate Services, UNS Energy Affiliates (6)
1

 
1

 
3

 
2

(1) 
TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable Open Access Transmission Tariff.
(2) 
TEP charges UNS Electric for Control Area Services under a FERC-approved Control Area Services Agreement.
(3) 
Common Costs (information systems, facilities, etc.) are allocated on a cost-causative basis and recorded as revenue by TEP. The method of allocation is deemed reasonable by management and is reviewed by the ACC as part of the rate case process.
(4) 
SES provides supplemental workforce and meter-reading services to TEP based on related party service agreements. The charges are based on cost of services performed and deemed reasonable by management.
(5) 
Costs for Corporate Services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 82% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis management fees. TEP's share of Fortis' management fees were $1 million and $3 million for the three and six months ended June 30, 2018, respectively, and $1 million and $2 million, for the three and six months ended June 30, 2017, respectively.
(6) 
Costs for Corporate Services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.
DIVIDENDS PAID TO PARENT
On July 23, 2018, TEP declared a $40 million dividend to UNS Energy which was paid July 27, 2018.

NOTE 6. DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS
There have been no significant changes to TEP's debt, credit facility, or capital lease obligations from those reported in its 2017 Annual Report on Form 10-K, except as noted below.
CREDIT FACILITY
TEP's unsecured credit agreement includes the following:
 
Capacity
 
LOC
 Sub-Limit
 
Borrowed
 
Available
 
Weighted Average Interest Rate
 
Pricing (1)
($ in millions)
June 30, 2018
Credit Facility
$
250

 
$
50

 
$
8

 
$
242

 
3.09
%
 
LIBOR + 1.000% or ABR + 0.00%
(1) 
Interest rates and fees under the credit facility are based on a pricing grid tied to TEP's credit rating.
As of July 30, 2018, TEP had $207 million available under its revolving credit commitments and Letter of Credit (LOC) facility.

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CAPITAL LEASE OBLIGATIONS
In 2017, TEP entered into a 20-year tolling PPA with Salt River Project Agricultural Improvement and Power District (SRP) to purchase and receive all 550 megawatt (MW) of capacity, power, and ancillary services from Gila River Unit 2 with a 3-year call option to purchase the unit (Tolling PPA). TEP’s obligations under the agreement were contingent upon SRP's acquisition of Gila River Generating Station (Gila River) Units 1 and 2 from third-parties (Gila Acquisition). In May 2018 as a result of SRP completing the Gila Acquisition, TEP recorded an increase of $165 million to both Long Term Liabilities—Capital Lease Obligations and Utility Plant Under Capital Leases on the Condensed Consolidated Balance Sheets. The amount reflects the fair value of the unit which is determined by SRP's purchase price, subject to final customary closing adjustments. TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $165 million. Over the expected 20-month lease term, TEP will pay a monthly demand charge consisting of: (i) a fixed capacity charge of approximately $1 million, and (ii) an operating fee to compensate SRP for the non-fuel costs of operating Gila River Unit 2. TEP expects to recover the monthly capacity charge and operating fee through the PPFAC.
TEP’s minimum lease payments consist of the fixed capacity charge and purchase option price. As of June 30, 2018, capital lease obligations related to the Tolling PPA mature on the following dates:
(in millions)
Capital Lease Obligations
2018
$
6

2019
177

2020
2

2021
—

2022
—

Total 2018-2022
185

Thereafter
—

Less: Imputed Interest
(20
)
Total
$
165

TEP recorded $2 million of capital lease interest in Purchased Power on the Condensed Consolidated Statements of Income for the three and six months ended June 30, 2018, and $1 million of amortization in Regulatory and Other Assets—Regulatory Assets on the Condensed Consolidated Balance Sheets related to the Tolling PPA capital lease as of June 30, 2018.

NOTE 7. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
In addition to those reported in our 2017 Annual Report on Form 10-K, TEP entered into the following long-term commitments through June 30, 2018:
(in millions)
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter
 
Total
Fuel, Including Transportation
$
4

 
$
5

 
$
5

 
$
5

 
$
5

 
$
1

 
$
25

Fuel, Including Transportation
TEP has firm transportation agreements with capacity sufficient to meet its load requirements. These agreements expire in various years between 2019 and 2040. In January 2018, TEP entered into a transportation agreement with El Paso Natural Gas Company, LLC, extending the expiration date of the existing agreement from April 2018 to April 2023.
CONTINGENCIES
Legal Matters
TEP is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. TEP believes such normal and routine litigation will not have a material impact on its operations or financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts on TEP and are disclosed below.

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Claims Related to San Juan Generating Station
WildEarth Guardians
In 2013, WildEarth Guardians (WEG) filed a Petition for Review in the U.S. District Court for the District of Colorado against the Office of Surface Mining (OSM) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to San Juan Coal Company’s (SJCC) San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSM, including: (i) failure to provide requisite public notice and participation, and (ii) failure to analyze certain environmental impacts. WEG’s petition seeks various forms of relief, including voiding and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the approvals until they can demonstrate compliance with the NEPA, and enjoining operations at the affected mines. SJCC intervened in this matter and was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now pending. In July 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSM so the OSM may prepare a new environmental impact statement (EIS) under the NEPA regarding the impacts of the San Juan Mine mining plan approval. In August 2016, the court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provides that: (i) the OSM's decision approving the mining plan will remain in effect during this process; or (ii) if the EIS is not completed by August 31, 2019, then the approved mine plan will immediately be vacated, absent further court order. In May 2018, the OSM released a draft EIS for public comment open through July 2018. TEP cannot currently predict the outcome of this matter or the range of its potential impact.
Mine Reclamation at Generation Facilities Not Operated by TEP
TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $68 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The balance sheet reflected a total liability related to reclamation of $36 million as of June 30, 2018, and $34 million as of December 31, 2017.
Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.
TEP’s PPFAC allows the Company to pass through final mine reclamation costs, as a component of fuel costs, to retail customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.
Performance Guarantees
TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and Luna Generating Station (Luna). The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear its 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 generation capacity of the defaulting participant. With the exception of Four Corners, there is no maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of June 30, 2018, there have been no such payment defaults under any of the participation agreements. The Navajo participation agreement expires in 2019, San Juan in 2022, Four Corners in 2041, and Luna in 2046.
Environmental Matters
TEP is subject to federal, state, and local environmental laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species, and other environmental matters that have the potential to impact TEP's current and future operations. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, TEP is unable to predict the impact of the changing laws and regulations on its operations and financial results. TEP expects to recover the cost of environmental compliance from its ratepayers. TEP believes it is in compliance with applicable environmental laws and regulations.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



NOTE 8. EMPLOYEE BENEFIT PLANS
Net periodic benefit cost includes the following components:
 
Pension Benefits
 
Other Postretirement Benefits
 
Three Months Ended June 30,
(in millions)
2018
 
2017
 
2018
 
2017
Service Cost
$
3

 
$
3

 
$
1

 
$
1

Interest Cost
4

 
4

 
1

 
1

Expected Return on Plan Assets
(7
)
 
(6
)
 
—

 
—

Amortization of Net Loss
2

 
2

 
—

 
—

Net Periodic Benefit Cost
$
2

 
$
3

 
$
2

 
$
2

 
Six Months Ended June 30,
(in millions)
2018
 
2017
 
2018
 
2017
Service Cost
$
7

 
$
6

 
$
2

 
$
2

Interest Cost
8

 
8

 
1

 
1

Expected Return on Plan Assets
(14
)
 
(12
)
 
—

 
—

Amortization of Net Loss
4

 
4

 
—

 
—

Net Periodic Benefit Cost
$
5

 
$
6

 
$
3

 
$
3

The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.

NOTE 9. SUPPLEMENTAL CASH FLOW INFORMATION
NON-CASH TRANSACTIONS
Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:
 
Six Months Ended June 30,
(in millions)
2018
 
2017
Gila River Unit 2, Capital Lease (1)
$
165

 
$
—

Net Cost of Removal Decrease (2)
(6
)
 
(82
)
Accrued Capital Expenditures
24

 
17

Renewable Energy Credits
5

 
5

(1) 
Subject to final customary closing adjustments. See Note 6 for additional information.
(2) 
Non-cash Net Cost of Removal represents an accrual for future cost of retirement net of salvage values that does not impact earnings. As approved in the 2017 Rate Order, TEP implemented new depreciation reserves and rates effective March 1, 2017. See Note 2 for additional information.

NOTE 10. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
TEP categorizes financial instruments into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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 classified in their entirety based on the lowest level of input that is significant to the fair value measurement:
 
Level 1
 
Level 2
 
Level 3
 
Total
(in millions)
June 30, 2018
Assets
 
Cash Equivalents(1)
$
—

 
$
—

 
$
—

 
$
—

Restricted Cash(1)
10

 
—

 
—

 
10

Energy Derivative Contracts, Regulatory Recovery(2)
—

 
4

 
2

 
6

Energy Derivative Contracts, No Regulatory Recovery(2)
—

 
—

 
5

 
5

Total Assets
10

 
4

 
7

 
21

Liabilities
 
 
 
 
 
 
 
Energy Derivative Contracts, Regulatory Recovery(2)
—

 
(55
)
 
(1
)
 
(56
)
Energy Derivative Contracts, No Regulatory Recovery(2)
—

 
—

 
(1
)
 
(1
)
Interest Rate Swap(3)
—

 
(1
)
 
—

 
(1
)
Total Liabilities
—

 
(56
)
 
(2
)
 
(58
)
Total Assets (Liabilities), Net
$
10

 
$
(52
)
 
$
5

 
$
(37
)
(in millions)
December 31, 2017
Assets
 
Cash Equivalents(1)
$
30

 
$
—

 
$
—

 
$
30

Restricted Cash(1)
12

 
—

 
—

 
12

Energy Derivative Contracts, Regulatory Recovery(2)
—

 
9

 
—

 
9

Energy Derivative Contracts, No Regulatory Recovery(2)
—

 
—

 
3

 
3

Total Assets
42

 
9

 
3

 
54

Liabilities
 
 
 
 
 
 
 
Energy Derivative Contracts, Regulatory Recovery(2)
—

 
(26
)
 
—

 
(26
)
Energy Derivative Contracts, No Regulatory Recovery(2)
—

 
—

 
(1
)
 
(1
)
Interest Rate Swap(3)
—

 
(1
)
 
—

 
(1
)
Total Liabilities
—

 
(27
)
 
(1
)
 
(28
)
Total Assets (Liabilities), Net
$
42

 
$
(18
)
 
$
2

 
$
26

(1) 
Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets.
(2) 
Energy Derivative Contracts include gas swap agreements (Level 2) and forward purchased power and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.
(3) 
The Interest Rate Swap is valued using an income valuation approach based on the 6-month London Interbank Offered Rate and is included in Derivative Instruments on the Condensed Consolidated Balance Sheets.
All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



 
Gross Amount Recognized in the Balance Sheets
 
Gross Amount Not Offset in the Balance Sheets
 
Net Amount
 
 
Counterparty Netting of Energy Contracts
 
Cash Collateral Received/Posted
 
(in millions)
June 30, 2018
Derivative Assets
 
 
 
 
 
 
 
Energy Derivative Contracts
$
11

 
$
6

 
$
—

 
$
5

Derivative Liabilities
 
 
 
 
 
 
 
Energy Derivative Contracts
(57
)
 
(6
)
 
—

 
(51
)
Interest Rate Swap
(1
)
 
—

 
—

 
(1
)
(in millions)
December 31, 2017
Derivative Assets
 
 
 
 
 
 
 
Energy Derivative Contracts
$
12

 
$
10

 
$
—

 
$
2

Derivative Liabilities
 
 
 
 
 
 
 
Energy Derivative Contracts
(27
)
 
(10
)
 
—

 
(17
)
Interest Rate Swap
(1
)
 
—

 
—

 
(1
)
DERIVATIVE INSTRUMENTS
TEP enters into various derivative and non-derivative contracts to reduce exposure to energy price risk associated with its natural gas and purchased power requirements. The objectives for entering into such contracts include: (i) creating price stability; (ii) meeting load and reserve requirements; and (iii) reducing exposure to price volatility that may result from delayed recovery under the PPFAC mechanism.
The Company primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.
For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The Company primarily uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes 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, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses.
TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
The inputs and the Company's 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. TEP reviews the assumptions underlying its price curves monthly.
Cash Flow Hedges
To mitigate the exposure to volatility in variable interest rates on debt, TEP has an interest rate swap agreement that expires January 2020. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months and the realized losses recorded related to the cash flow hedge for the three and six months ended June 30, 2018 and 2017, are not material to TEP's financial position or results of operations.
As of June 30, 2018, the total notional amount of the interest rate swap was $12 million.
Energy Derivative Contracts, Regulatory Recovery
TEP records unrealized gains and losses on energy purchase contracts that are recoverable through the PPFAC mechanism on the balance sheet as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statement or in

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



the statement of other comprehensive income, as shown in the following table:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in millions)
2018
 
2017
 
2018
 
2017
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities
$
(14
)
 
$
—

 
$
(32
)
 
$
(6
)
Energy Derivative Contracts, No Regulatory Recovery
TEP enters into certain contracts that qualify as derivatives but do not meet the regulatory recovery criteria. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition, as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income were as follows:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in millions)
2018
 
2017
 
2018
 
2017
Operating Revenues
$
4

 
$
4

 
$
5

 
$
4

Derivative Volumes
As of June 30, 2018, TEP had energy contracts that will settle on various expiration dates through 2029. The volumes associated with the energy contracts were as follows:
 
June 30, 2018
 
December 31, 2017
Power Contracts GWh
4,946

 
2,589

Gas Contracts BBtu
152,823

 
137,952

Level 3 Fair Value Measurements
The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:
 
Valuation Approach
 
Fair Value of
 
 
 
Range of Unobservable Input
 
 
Assets
 
Liabilities
 
Unobservable Inputs
 
(in millions)
June 30, 2018
Forward Power Contracts
Market approach
 
$
7

 
$
(2
)
 
Market price per MWh
 
$
16.30

 
$
54.15

(in millions)
December 31, 2017
Forward Power Contracts
Market approach
 
$
3

 
$
(1
)
 
Market price per MWh
 
$
17.65

 
$
34.60

Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in millions)
2018
 
2017
 
2018
 
2017
Beginning of Period
$
1

 
$
1

 
$
2

 
$
1

Gains (Losses) Recorded
 
 
 
 
 
 
 
Regulatory Assets or Liabilities, Derivative Instruments
—

 
—

 
—

 
2

Operating Revenues
4

 
4

 
4

 
4

Settlements
—

 
(1
)
 
(1
)
 
(3
)
End of Period
$
5

 
$
4

 
$
5

 
$
4

 
 
 
 
 
 
 
 
Gains (Losses), Assets (Liabilities) Still Held
$
6

 
$
5

 
$
5

 
$
4

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. TEP enters into contracts for the physical delivery of power and natural 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.
TEP has contractual agreements for energy procurement and hedging activities that contain certain provisions requiring TEP and its counterparties to post collateral under certain circumstances. These circumstances include: (i) exposures in excess of unsecured credit limits; (ii) credit rating downgrades; or (iii) a failure to meet certain financial ratios. In the event that such credit events were to occur, the Company, or its counterparties, would have to provide certain credit enhancements in the form of cash, a LOC, or other acceptable security to collateralize exposure beyond the allowed amounts.
TEP considers 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 then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the individual contracts.
The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $93 million as of June 30, 2018, compared with $27 million as of December 31, 2017. As of June 30, 2018, TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on June 30, 2018, TEP would have been required to post an additional $93 million of collateral of which $13 million relates to outstanding net payable balances for settled positions.
FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE
The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. Borrowings under revolving credit facilities approximate fair value due to the short-term nature of these financial instruments. These items have been excluded from the table below.
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The following table includes the face value and estimated fair value of TEP's long-term debt:
 
Fair Value Hierarchy
 
Face Value
 
Fair Value
(in millions)
 
June 30, 2018
 
December 31, 2017
 
June 30, 2018
 
December 31, 2017
Liabilities
 
 
 
 
 
 
 
 
 
Long-Term Debt, including Current Maturities
Level 2
 
$
1,466

 
$
1,466

 
$
1,487

 
$
1,547



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

NOTE 11. INCOME TAXES
Income tax expense differs from the amount of income tax determined by applying the statutory federal income tax rate of 21% in 2018 and 35% in 2017 to pre-tax income due to the following:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
(in millions)
2018
 
2017
 
2018
 
2017
Federal Income Tax Expense at Statutory Rate
$
14

 
$
33

 
$
20

 
$
43

State Income Tax Expense, Net of Federal Deduction
3

 
3

 
4

 
4

Federal/State Tax Credits
(2
)
 
(3
)
 
(4
)
 
(4
)
Excess Deferred Income Taxes
(3
)
 
—

 
(4
)
 
—

Other
—

 
(1
)
 
—

 
(1
)
Total Federal and State Income Tax Expense
$
12

 
$
32

 
$
16

 
$
42

On December 22, 2017, the President of the United States of America signed into law the TCJA, which enacted significant changes to the Internal Revenue Code including a reduction in the federal corporate income tax rate from up to 35% to 21% effective for tax years beginning after 2017. In addition, the TCJA provided modifications to bonus depreciation rules and limitations on the deductibility of interest expense, both of which include carve-outs for regulated utilities.
As a result of the TCJA, the Company was required to revalue its deferred tax assets and liabilities at the new federal tax rate as of the date of enactment. This resulted in a net decrease to deferred income tax liabilities and the establishment of a regulatory liability related to EDIT. TEP is amortizing the EDIT balance in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining life of the related plant. In April 2018, the ACC Refund Order was approved requiring TEP to share EDIT amortization of the ACC-jurisdictional assets with customers. The EDIT balance related to the effects of the TCJA included in Regulatory Liabilities on the Condensed Consolidated Balance Sheets was $337 million as of June 30, 2018. See Note 2 for additional information regarding the ACC Refund Order and the FERC NOI.
TEP is still in the process of evaluating the bonus depreciation carve-out for regulated utilities and anticipates further clarification from the Internal Revenue Service. TEP has not recorded any additional estimated provision for bonus depreciation since the adjustment made as of December 31, 2017.

NOTE 12. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
TEP considers the applicability and impact of all Accounting Standard Updates (ASU) issued by the Financial Accounting Standards Board (FASB). The following updates have been issued, but have not yet been adopted by TEP. Updates not listed below were assessed and either determined to not be applicable or are expected to have a minimal impact on TEP's financial position, results of operations, and disclosures.
LEASES
In February 2016, the FASB issued an ASU that will require the recognition of leased assets and liabilities by lessees for those leases classified as operating leases and disclosure of additional quantitative and qualitative information about leasing arrangements. The standard is effective for periods beginning January 1, 2019, and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. In January 2018, the FASB issued an additional optional practical expedient that permits entities to not evaluate existing land easements that were not previously accounted for as leases. TEP plans to adopt this guidance, including the practical expedients, effective January 1, 2019 and is evaluating the impact of this ASU to its financial position and disclosures.
TEP’s leasing activities accounted for as operating leases primarily relate to leases for land, rail cars, and office facilities. The adoption of the new guidance will affect the Company’s Condensed Consolidated Balance Sheets as the Company will be required to record lease assets and lease liabilities related to these operating lease arrangements. TEP is currently evaluating the significance of the expected balance sheet impacts and preparing the expanded lease disclosures. The Company does not expect the new ASU to materially affect its results of operations or cash flows. Management continues to monitor standard-setting activities that may affect the transition requirements of the new lease standard.


23
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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 financial condition, and the outlook for TEP. It includes the following:
•
outlook and strategies;
•
operating results in the second quarter and first six months of 2018 compared with the same periods in 2017;
•
factors affecting our results of operations and outlook;
•
liquidity and capital resources including contractual obligations, capital expenditures, and environmental matters;
•
critical accounting policies and estimates; and
•
recent accounting pronouncements.
Management’s Discussion and Analysis includes financial information prepared in accordance with GAAP financial measures.
Management’s Discussion and Analysis should be read in conjunction with the financial statements and accompanying notes that appear in Part I, Item 1 of this Form 10-Q. For information on factors that may cause our 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 2017 Annual Report on Form 10-K, and in Part II, Item 1A of this Form 10-Q.
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: (i) global, national, regional, and local economic conditions; (ii) volatility in the financial markets; (iii) environmental laws and regulations; and (iv) other regulatory factors.
Our plans and strategies include the following:
•
Achieving constructive outcomes in our regulatory proceedings that provide us: (i) recovery of our full cost of service and an opportunity to earn an appropriate return on our rate base investments; (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers; and (iii) the ability to continue providing safe and reliable service.
•
Continuing to focus on our long-term resource diversification 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, leveraging and improving our existing utility infrastructure, and maintaining financial strength. This long-term strategy includes a target of meeting 30% of our customers’ energy needs with non-carbon emitting resources by 2030. This resource strategy may be impacted by various energy policy proposals currently under consideration in Arizona.
•
Focusing on our core utility business through operational excellence, promoting economic development in our service territory, investing in infrastructure to ensure reliable service, and maintaining a strong community presence.
2018 Operational and Financial Highlights
Management's Discussion and Analysis includes the following notable items:
•
In April 2018, the ACC Refund Order was approved effective May 1, 2018. The Order provides that we refund customers a total of $36.5 million through a bill credit in 2018. In 2019 and through the completion of our next rate case, TEP will continue to return savings to customers through a combination of a bill credit and a regulatory liability.
•
In May 2018, we responded to the FERC Refund Order with a proposed overall transmission rate reduction, reflecting the lower federal tax rate, to be effective March 21, 2018. TEP cannot predict the outcome of the order.
•
In May 2018, TEP recorded an increase of $165 million to both capital lease assets and liabilities related to the 20-year Tolling PPA with SRP entered into in 2017. The amount reflects the fair value of the unit which is determined by SRP's purchase price, subject to final customary closing adjustments. The additional 550 MW of capacity, power, and ancillary services will allow us to continue to move toward our long-term goal of resource diversification.

24

Table of Contents

RESULTS OF OPERATIONS
The following discussion provides the significant items that affected TEP's results of operations in the second quarter and first six months of 2018 compared with the same periods in 2017. The significant items affecting net income are presented on an after-tax basis.
The second quarter of 2018 compared with the second quarter of 2017
TEP reported net income of $58 million in the second quarter of 2018 compared with net income of $61 million in the second quarter of 2017. The decrease of $3 million, or 5%, was primarily due to:
•
$8 million in lower retail revenue associated with the ACC Refund Order to return savings related to the TCJA to customers. The order was effective May 1, 2018. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the ACC Refund Order;
•
$5 million in higher operations and maintenance expense resulting primarily from an increase in maintenance expense related to planned generation outages in 2018 and sales tax refunds that offset operation and maintenance expense in 2017; and
•
$3 million related to the reversal of accrued refunds in 2017 associated with late-filed TSAs. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
The decrease was partially offset by:
•
$12 million in lower income tax expense due to the reduction of the federal effective income tax rate primarily related to the enactment of the TCJA. See Note 11 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the TCJA.
The first six months of 2018 compared with the first six months of 2017
TEP reported net income of $81 million in the first six months of 2018 compared with net income of $82 million in the first six months of 2017. The decrease of $1 million, or 1%, was primarily due to:
•
$14 million in lower retail revenue associated with the ACC Refund Order to return savings related to the TCJA to customers. The order was effective May 1, 2018. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the ACC Refund Order;
•
$8 million in lower income from a settlement agreement and the reversal of accrued refunds associated with late-filed TSAs in 2017. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the settlement agreement; and
•
$5 million in higher operations and maintenance expense resulting primarily from an increase in maintenance expense related to planned generation outages in 2018 and sales tax refunds that offset operations and maintenance expense in 2017.
The decrease was partially offset by:
•
$17 million in lower income tax expense due to the reduction of the federal effective income tax rate primarily related to the enactment of the TCJA. See Note 11 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the TCJA; and
•
$9 million in higher retail revenue primarily due to an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017.

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Retail Revenues and Key Statistics
The following table provides key statistics impacting operating revenues:
 
Three Months Ended June 30,
 
Increase (Decrease)
 
Six Months Ended June 30,
 
Increase (Decrease)
($ and kWh in millions)
2018
 
2017
 
Percent
 
2018
 
2017
 
Percent
Operating Revenues
$
354

 
$
352

 
0.6
 %
 
$
629

 
$
621

 
1.3
 %
 
 
 
 
 
 
 
 
 
 
 
 
Electric Sales (kWh)
 
 
 
 
 
 
 
 
 
 
 
Residential
1,018

 
1,019

 
(0.1
)%
 
1,666

 
1,705

 
(2.3
)%
Commercial
574

 
579

 
(0.9
)%
 
1,001

 
1,019

 
(1.8
)%
Industrial
498

 
483

 
3.1
 %
 
938

 
928

 
1.1
 %
Mining
249

 
250

 
(0.4
)%
 
501

 
495

 
1.2
 %
Public Authorities
4

 
4

 
—
 %
 
8

 
9

 
(11.1
)%
Total Retail Sales
2,343

 
2,335

 
0.3
 %
 
4,114

 
4,156

 
(1.0
)%
Wholesale, Long-Term
65

 
116

 
(44.0
)%
 
144

 
200

 
(28.0
)%
Wholesale, Short-Term
1,131

 
728

 
55.4
 %
 
2,230

 
1,843

 
21.0
 %
Total Electric Sales
3,539

 
3,179

 
11.3
 %
 
6,488

 
6,199

 
4.7
 %
 
 
 
 
 
 
 
 
 
 
 
 
Average Revenue Per kWh (Cents/kWh)
 
 
 
 
 
 
 
 
 
 
 
Retail
11.66

 
11.79

 
(1.1
)%
 
11.31

 
11.23

 
0.7
 %
Wholesale
2.92

 
3.34

 
(12.6
)%
 
2.97

 
3.09

 
(3.9
)%
 
 
 
 
 
 
 
 
 
 
 
 
Total Retail Customers
 
 
 
 
 
 
424,242

 
421,850

 
0.6
 %
Operating Revenues increased by $2 million and $8 million in the second quarter and first six months of 2018, respectively, when compared with the same periods in 2017 primarily due to: (i) higher retail revenues related to an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017; (ii) an increase in short-term wholesale sales due to an increase in system capacity; (iii) an increase in participant billings related to Springerville Units 3 and 4; and (iv) an increase in the PPFAC rate. The increase was partially offset by the return of savings related to the TCJA to customers and a 2017 reversal of an accrual related to the FERC ordered refunds for late-filed TSAs. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the 2017 Rate Order, Cost Recovery Mechanisms, and the ACC Refund Order.
Short-term wholesale revenues are primarily related to ACC jurisdictional assets and are returned to retail customers by crediting the revenues against fuel and purchased power costs eligible for recovery through the PPFAC. Revenues related to Springerville Units 3 and 4 are primarily reimbursements by Tri-State Generation and Transmission Association, Inc., the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with the corresponding expense recorded in Operating Expenses on the Condensed Consolidated Statements of Income.
Operating Expenses
Fuel and Purchased Power Expense
Fuel and Purchased Power Expense, which includes PPFAC recovery treatment, increased by $14 million, or 14%, and $13 million, or 7%, in the second quarter and first six months of 2018, respectively, when compared with the same periods in 2017. The increase was primarily due to an increase in recovery of PPFAC costs as a result of changes in the PPFAC rate and an increase in generation volumes. The increase was partially offset by a decrease in Purchased Power, Non-Renewable volumes, and the average cost of Natural Gas.

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The following table presents TEP’s sources of energy and average cost of power by type:
 
Three Months Ended June 30,
 
Increase (Decrease)
 
Six Months Ended June 30,
 
Increase (Decrease)
(kWh in millions)
2018
 
2017
 
Percent
 
2018
 
2017
 
Percent
Sources of Energy
 
 
 
 
 
 
 
 
 
 
 
Coal-Fired Generation
1,550

 
1,543

 
0.5
 %
 
3,264

 
3,552

 
(8.1
)%
Gas-Fired Generation
1,415

 
746

 
89.7
 %
 
2,297

 
1,275

 
80.2
 %
Utility-Owned Renewable Generation
26

 
27

 
(3.7
)%
 
44

 
45

 
(2.2
)%
Total Generation
2,991

 
2,316

 
29.1
 %
 
5,605

 
4,872

 
15.0
 %
Purchased Power, Non-Renewable
521

 
862

 
(39.6
)%
 
832

 
1,325

 
(37.2
)%
Purchased Power, Renewable
210

 
211

 
(0.5
)%
 
365

 
367

 
(0.5
)%
Total Generation and Purchased Power
3,722

 
3,389

 
9.8
 %
 
6,802

 
6,564

 
3.6
 %
(cents per kWh)
 
 
 
 
 
 
 
 
 
 
 
Average Fuel Cost of Generated Power
 
 
 
 
 
 
 
 
 
 
 
Coal
2.16

 
2.21

 
(2.3
)%
 
2.46

 
2.30

 
7.0
 %
Natural Gas
1.97

 
3.30

 
(40.3
)%
 
2.09

 
3.30

 
(36.7
)%
Average Cost of Purchased Power
 
 
 
 
 
 
 
 
 
 
 
Purchased Power, Non-Renewable
3.08

 
3.78

 
(18.5
)%
 
3.02

 
3.50

 
(13.7
)%
Purchased Power, Renewable
9.49

 
9.52

 
(0.3
)%
 
9.40

 
9.45

 
(0.5
)%
Operations and Maintenance Expense
Operations and Maintenance Expense increased by $9 million, or 11%, and $10 million, or 6%, in the second quarter and first six months of 2018, respectively, when compared with the same periods in 2017. The increase was primarily due to: (i) an increase in maintenance expense related to planned generation outages; (ii) an increase in maintenance expense at Springerville Units 3 and 4; and (iii) a sales tax refund that occurred in 2017.
Expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State Generation and Transmission Association, Inc., the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with corresponding amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income.
Other Income (Expense)
There were no significant changes to Other Income (Expense) in the second quarter of 2018 when compared with the same period in 2017. Other Income (Expense) decreased by $7 million, or 34%, in the first six months of 2018 when compared with the same period in 2017. The decrease was primarily due to a settlement agreement related to late-filed TSAs in January 2017. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the settlement agreement.
Income Tax Expense
Income Tax Expense decreased by $20 million, or 62%, and $25 million, or 61%, in the second quarter and first six months of 2018, respectively, when compared with the same periods in 2017. The decrease was primarily due to the reduction of the federal corporate income tax rate related to the enactment of the TCJA and a decrease in earnings before tax expense. See Note 11 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the TCJA.
FACTORS AFFECTING RESULTS OF OPERATIONS
Regulatory Matters
TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Part II, Item 7 of our 2017 Annual Report on Form 10-K and new regulatory matters occurring in 2018.

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2017 Rate Order
Provisions of the 2017 Rate Order include, but are not limited to:
•
a non-fuel base rate increase of $81.5 million, a cost of equity component of 9.75%, and a cost of debt component of 4.32%; and
•
adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1.
The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2. See Distributed Generation below.
Distributed Generation
In 2016, the ACC approved an order related to the Value and Cost of DG docket that began to reform net metering in Arizona. The order adopted a number of net metering changes and polices including a requirement that TEP establish a DG export rate and create separate rate classes for new DG customers. The ACC deferred matters related to the DG export rate and rate design for new DG customers to Phase 2, which is expected to be completed by the end of 2018. TEP cannot predict the outcome of these proceedings.
Federal Income Tax Legislation
Arizona Corporation Commission
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the ongoing benefits of the TCJA through to customers. In April 2018, the ACC Refund Order was approved effective May 1, 2018. The Order provides that we refund customers a total of $36.5 million through a bill credit in 2018. In 2019 and through the completion of our next rate case, we will continue to return savings to customers through a combination of a bill credit and a regulatory liability. The customer bill credit will be trued-up annually to reflect actual kWh sales and EDIT amortization. The regulatory liability will accrue interest and be returned to customers as part of our next rate case. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the ACC Refund Order.
Federal Energy Regulatory Commission
In March 2018, the FERC issued the FERC Refund Order. In May 2018, TEP responded to the order and proposed an overall transmission rate reduction of approximately 5.3%, reflecting the lower federal tax rate, to be effective March 21, 2018. TEP estimates that the proposed rate reduction will reduce operating revenues by approximately $2 million on an annual basis. TEP cannot predict the outcome of the order.
Also in March 2018, the FERC issued a NOI regarding the effect of the TCJA. The NOI seeks comments on a number of issues including how to return the amortization of the EDIT regulatory liability balances in rates. TEP is amortizing the EDIT balance in accordance with applicable federal income tax laws, which require the amortization of a majority of the balance over the remaining life of the related plant. TEP cannot currently predict the impact the NOI will have on its current EDIT amortization.
See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the FERC Refund Order and NOI.
Generating Resources
TEP’s long-term strategy is to shift to a more diverse, sustainable energy portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generation resources. TEP's existing coal-fired generation fleet faces a number of uncertainties impacting the viability of continued operations, including competition from other resources, fuel supply and land lease contract extensions, environmental regulations, and, for jointly owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, TEP may consider options that include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions.
As of June 30, 2018, approximately 40% of TEP's generation capacity was from coal-fired generation resources.
See Part I, Item 2. Liquidity and Capital Resources, Environmental Matters of this Form 10-Q for additional information regarding the impact of environmental matters on generation facility operations.

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Arizona Ballot Initiative
In February 2018, a coalition of renewable energy advocates filed an application with the Office of the Secretary of State for the State of Arizona requesting an amendment of the state constitution that would require most Arizona utilities to generate at least 50% of their annual sales of electricity from renewable energy resources by 2030. The amendment, if passed in the November 2018 general election, would increase our current target of meeting 30% of our customers’ energy needs with non-carbon emitting resources by 2030. TEP cannot predict the outcome of this initiative or the impact on the Company's financial position or results of operations.
Arizona Energy Modernization Plan
The ACC may consider adoption of a new energy policy that would establish a goal to have clean energy sources make up at least 80% of most Arizona utilities' electricity generation portfolios by 2050. The adoption of a new policy would be subject to a rulemaking proceeding at the ACC. TEP cannot predict the outcome of this proposal or the impact on the Company's financial position or results of operations.
Navajo Generating Station
In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. We are currently recovering Navajo capital and operating costs in base rates using a useful life through 2030. We plan to seek recovery of all unrecovered costs in our next ACC rate case.
See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the planned early retirement of Navajo.
Sundt Generating Station
In 2017, TEP submitted an Application to the Pima County Department of Environmental Quality related to a generation modernization project at Sundt. In conjunction with the project, TEP will discontinue operation of Sundt Units 1 and 2 prior to commercial operation of the Reciprocating Internal Combustion Engines (RICE). We plan to seek recovery of all unrecovered costs in our next ACC rate case.
Under the project outlined in the Application, TEP will put into service 10 RICE units with a total nominal generation capacity of 190 MW. The initial 95 MW are scheduled for commercial operation in the third quarter of 2019 and the remaining 95 MW in the fourth quarter of 2019. The RICE units will balance the variability of intermittent renewable energy resources and will replace 162 MW of nominal net generation capacity from Sundt Units 1 and 2, which are less efficient and lack the quick start, fast ramp capabilities of RICE units.
See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the planned early retirement of Sundt Units 1 and 2.
Gila River Generating Station
In 2017, TEP entered into the Tolling PPA agreement. TEP’s obligations under the agreement were contingent upon SRP's completion of the Gila Acquisition. As a result of SRP completing the Gila Acquisition in May 2018, TEP recorded an increase of $165 million to both Long Term Liabilities—Capital Lease Obligations and Utility Plant Under Capital Leases on the Condensed Consolidated Balance Sheets. The amount reflects the fair value of the unit which is determined by SRP's purchase price, subject to final customary closing adjustments. TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $165 million. Over the expected 20-month lease term, TEP will pay a monthly demand charge consisting of: (i) a fixed capacity charge of approximately $1 million, and (ii) an operating fee to compensate SRP for the non-fuel costs of operating Gila River Unit 2. TEP expects to recover the monthly capacity charge and operating fee through the PPFAC.
The additional 550 MW of capacity, power, and ancillary services from the Tolling PPA will allow us to continue to move toward our long-term goal of resource diversification as it will replace coal-fired generation scheduled for early retirement. TEP sells the capacity from the Tolling PPA into the wholesale market on a short-term basis with the associated revenues credited to the PPFAC.
See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the Tolling PPA.

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Interest Rates
See Part II, Item 7A in our 2017 Annual Report on Form 10-K and Part II, Item 3 of this Form 10-Q for information regarding interest rate risks and its impact on earnings.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Cash flows may vary during the year with cash flows from operations being typically the lowest in the first quarter of the year and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flows, we will use, as needed, our revolving credit facility to assist in funding our business activities. We believe that we have sufficient liquidity under our revolving credit facility to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which TEP has access to external financing depends on a variety of factors, including its credit ratings and conditions in the overall capital markets.
Available Liquidity
(in millions)
June 30, 2018
Cash and Cash Equivalents
$
6

Amount Available under Revolving Credit Facility (1)
242

Total Liquidity
$
248

(1) 
TEP's revolving credit facility provides for $250 million of revolving credit commitments with a LOC sublimit of $50 million and a maturity date of October 2022.
Future Liquidity Requirements
We expect to meet all of our financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include, but are not limited to, dividend payments, debt maturities, and obligations included in the Contractual Obligations and forecasted Capital Expenditures tables reported in our 2017 Annual Report on Form 10-K and the material changes summarized below in the respective sections.
Summary of Cash Flows
Effective December 31, 2017, TEP early adopted accounting guidance that requires entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents on the cash flow statement. The new accounting guidance is applied retrospectively affecting all periods presented.
The table below incorporates the new accounting guidance and presents net cash provided by (used for) operating, investing and financing activities and its effect on cash, cash equivalents, and restricted cash:
 
Six Months Ended June 30,
 
Increase (Decrease)
(in millions)
2018
 
2017
 
Percent
Operating Activities
$
198

 
$
170

 
16.5
 %
Investing Activities
(193
)
 
(176
)
 
9.7
 %
Financing Activities
(38
)
 
(14
)
 
*

Net Decrease
(33
)
 
(20
)
 
*

Beginning of Period
50

 
43

 
16.3
 %
End of Period (1)
$
17

 
$
23

 
(26.1
)%
* Not meaningful
(1) 
Calculated on unrounded data and may not correspond exactly to data shown in table.
Operating Activities
In the first six months of 2018, net cash flows from operating activities increased by $28 million compared with the same period in 2017. The increase is primarily due to: (i) an increase in rates as approved in the 2017 Rate Order that took effect February 27, 2017; (ii) an increase in recovery of costs as a result of changes in the PPFAC rate and an increase in generation

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volumes; and (iii) changes in working capital related to the timing of billing collections and payments. The increase was offset by: (i) the return of savings related to the TCJA to customers; and (ii) $8 million in cash proceeds received from a settlement agreement associated with late-filed TSAs in January 2017.
Investing Activities
In the first six months of 2018, net cash flows used for investing activities increased by $17 million compared with the same period in 2017 primarily due to an increase in cash paid for capital expenditures.
Financing Activities
In the first six months of 2018, net cash flows used for financing activities increased by $24 million compared with the same period in 2017 primarily due to an increase in repayments, net of proceeds borrowed, under our revolving credit facility.
Sources of Liquidity
Short-Term Investments
Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of June 30, 2018, TEP's short-term investments included highly-rated and liquid money market funds.
Access to Revolving Credit Facility
We have access to working capital through a revolving credit agreement with lenders. TEP expects that amounts borrowed under the credit facility will be used for working capital and other general corporate purposes and that LOCs will be issued from time to time to support energy procurement and hedging transactions. As of June 30, 2018, there was $242 million available under the revolving credit commitments and LOC facility. As of July 30, 2018, TEP had $207 million available under its revolving credit commitments and LOC facility.
For details of TEP's credit facility see Note 6 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 2017 Annual Report on Form 10-K.
Debt Financing
We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. We are exposed to adverse changes in interest rates to the extent that we rely on variable rate financing. Our cost of capital is also affected by our credit ratings.
In 2016, the ACC issued an order granting TEP financing authority. The order extends and expands the previous financing authority by: (i) extending authority from December 2016 to December 2020; (ii) increasing the outstanding long-term debt limitation from $1.7 billion to $2.2 billion; (iii) allowing parent equity contributions of up to $400 million; and (iv) continuing the interest rate hedging authority.
We anticipate raising additional capital in the second half of 2018 to: (i) refinance tax-exempt local furnishing bonds that are subject to mandatory tender for purchase in November 2018; (ii) refinance callable tax-exempt pollution control bonds backed by an LOC which expires in February 2019; and (iii) ensure adequate revolving credit capacity. TEP has, from time to time, refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, TEP may refinance other debt issuances or make additional debt repurchases in the future.
In connection with the anticipated refinancing of the tax-exempt pollution control bonds backed by an LOC which expires in 2019, we anticipate the LOC and the 2010 Reimbursement Agreement will be terminated once the bonds are no longer outstanding.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. As of June 30, 2018, the S&P Global Ratings' and the Moody’s Investors Service's credit ratings of our senior unsecured debt were A- and A3, respectively.
Our credit ratings are dependent on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold TEP securities. Each rating should be evaluated independently of any other ratings.

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Certain of TEP's debt agreements contain pricing based on our credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest we pay on our borrowings and the amount of fees we pay for our LOCs and unused commitments.
Debt Covenants
Under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of June 30, 2018, TEP was in compliance with these covenants.
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.
Contribution from Parent
TEP received no equity contributions in the second quarter and first six months of 2018 and 2017.
Dividends Paid to Parent
TEP did not declare or pay dividends to UNS Energy in the second quarter and first six months of 2018 and 2017. On July 23, 2018, TEP declared a $40 million dividend to UNS Energy which was paid July 27, 2018.
Master Trading Agreements
TEP conducts its wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, 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, changes in TEP’s credit ratings, or material changes in TEP’s creditworthiness. As of June 30, 2018, TEP had posted no cash or LOCs as credit enhancements with its counterparties.
Capital Expenditures
Our routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. Capital expenditures in the first six months of 2018 were $175 million. Forecasted capital expenditures presented below for years ended December 31 exclude amounts for AFUDC and other non-cash items:
(in millions)
2018
 
2019
 
2020
 
2021
 
2022
Generation Facilities:
 
 
 
 
 
 
 
 
 
Renewable Energy (1)
$
10

 
$
62

 
$
169

 
$
9

 
$
—

Other Generation Facilities
206

 
262

 
76

 
122

 
56

Total Generation Facilities
216

 
324

 
245

 
131

 
56

Transmission and Distribution (2)
183

 
343

 
321

 
194

 
176

General and Other (3)
120

 
87

 
61

 
53

 
64

Total Capital Expenditures
$
519

 
$
754

 
$
627

 
$
378

 
$
296

(1) 
Increase related to additional investments in renewable energy that will allow us to continue to move toward our long-term strategy of shifting to a more diverse, sustainable energy portfolio.
(2) 
Increase due to additional investments in transmission capacity and system reinforcements.
(3) 
Includes cost for information technology, fleet, facilities, and communication equipment.
These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to fluctuations in business and market conditions, construction schedules, possible early plant closures, changes in generation resources, environmental requirements, state or federal regulations, and other factors. We expect to pay for forecasted capital expenditures with internally generated funds and external financings, which may include issuances of long-term debt, other borrowings, or equity contributions.
Contractual Obligations
In the first six months of 2018, there have been no material changes outside the ordinary course of business to contractual obligations as reported in our 2017 Annual Report on Form 10-K, except as noted below:

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•
In January 2018, we extended the expiration date of a firm transportation agreement from April 2018 to April 2023. See Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
•
In May 2018, upon completion of the Gila Acquisition, we recorded a new capital lease obligation. See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Off-Balance Sheet Arrangements
Other than the unrecorded contractual obligations reported on the contractual obligations table presented in our 2017 Annual Report on Form 10-K, we do not have any arrangements or relationships with entities that are not consolidated into the financial statements.
Income Tax Position
Tax legislation previously in effect included provisions that made qualified property placed in service before 2018 eligible for bonus depreciation for tax purposes. In addition, the Internal Revenue Service had issued guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions were an acceleration of tax benefits we otherwise would have received over 20 years and created net operating loss carryforwards that may be used to offset future taxable income. As a result, we did not pay any federal or state income taxes in the first six months of 2018. We offset net operating loss carryforwards against taxable income and do not expect to make federal or state income tax payments until 2024.
Under the TCJA, Alternative Minimum Tax credit carryforwards will be refunded if not used to offset federal income tax liabilities. TEP expects to receive refunds of approximately $12 million in 2019, $6 million in 2020, and $3 million in 2021 and 2022.
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the ongoing benefits of the TCJA through to customers. In April 2018, the ACC Refund Order was approved effective May 1, 2018. The Order provides that we refund customers a total of $36.5 million through a bill credit in 2018. In 2019 and through the completion of our next rate case, we will continue to return savings to customers through a combination of a bill credit and a regulatory liability. The customer bill credit will account for 75% of the returned savings in 2019, and 50% of the returned savings in 2020 and through the completion of our next rate case. The remaining portion will be deferred as a regulatory liability and returned to customers through our next rate case.
See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the TCJA.
Environmental Matters
The Environmental Protection Agency (EPA) regulates the amount of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), particulate matter, mercury and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact of the changing laws and regulations on our operations and consolidated financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs. TEP will request recovery from its customers of the costs of environmental compliance through cost recovery mechanisms and Retail Rates.
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 rule calls 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 generation facilities.
In the western United States, Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install Selective Catalytic Reduction (SCR). The BART provisions do not apply to Springerville Units 1 and 2 since they were constructed in the 1980s, after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reductions are not likely to impact Springerville operations until after 2021. In December 2016, the EPA signed a final rule, entitled "Protection of Visibility: Amendments to Requirements for State Plans." Among other things, the rule changes the date for submittal of the next Regional Haze implementation plan from 2018 to 2021. Based

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on recent Regional Haze requirement time-frames, TEP anticipates that impacts, if any, to Springerville will likely occur three to five years after the 2021 plan submittal date. TEP cannot predict the ultimate outcome of these matters.
Four Corners Generating Station
In December 2013, Arizona Public Service Company (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 agreed to install SCR on Units 4 and 5. TEP owns 7% of Four Corners Units 4 and 5. APS completed the installation of SCR in July 2018. TEP's share of installation costs were approximately $47 million in capital expenditures and $2 million in annual operations and maintenance expenses.
Navajo Generating Station
In August 2014, the EPA published a final Federal Implementation Plan (FIP) which provides that: (i) one unit at Navajo will be shut down by 2020; (ii) SCR, or the equivalent, will be installed on the remaining two units by 2030; and (iii) conventional coal-fired generation will cease by December 2044. The final BART rule includes options that accommodate potential ownership changes at the facility. The facility had until December 2019 to notify the EPA of how it would comply with the FIP.
As a result of the planned early retirement of Navajo, TEP and the co-owners will no longer be responsible for implementing the FIP. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the early retirement of Navajo.
San Juan Generating Station
In October 2014, the EPA published a final rule approving a revised State Implementation Plan (SIP) covering BART requirements for San Juan, which included: (i) the closure of Units 2 and 3 by the end of December 2017; and (ii) the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4. TEP owns 50% of Units 1 and 2. Public Service Company of New Mexico, the operator of San Juan, completed the installation of SNCR in February 2016 and ceased operations at Units 2 and 3 in December 2017.
Greenhouse Gas Regulation
In August 2015, the EPA issued the Clean Power Plan (CPP) limiting CO2 emissions from existing and new fossil fueled generation facilities. The CPP establishes state-level CO2 emission rates and mass-based goals that apply to fossil fuel-fired generation. The plan targets CO2 emissions reductions for existing facilities by 2030 and establishes interim goals that begin in 2022.
In October 2017, the EPA issued a proposal to repeal the CPP and in December 2017, the EPA issued an Advance Notice of Proposed Rulemaking soliciting information about the intent to replace the CPP with a rule establishing new emissions guidelines. TEP will continue to work with the other Arizona and New Mexico utilities, as well as the appropriate regulatory agencies, to develop appropriate responses to the EPA's proposals and compliance strategies as needed. TEP is unable to determine the impact to its facilities until all legal challenges have been resolved and any new regulations have been promulgated.
Coal Combustion Residuals Regulation
In April 2015, the EPA issued a final rule requiring disposal of coal ash and other coal combustion residuals (CCR) to be managed as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA Subtitle D) for disposal in landfills and/or surface impoundments. Our share of costs to comply with the rule at Springerville was $2 million. The majority was spent through 2016 on capital expenditures associated with site preparation and installation of the groundwater monitoring well system. We continue to incur additional operating costs for on-going groundwater monitoring and eventual site closure activities. Similarly, we currently estimate our share of costs to be $4 million at Four Corners and $3 million at Navajo. San Juan does not operate any landfills or surface impoundments. San Juan currently disposes of CCR in the surface mine pits of San Juan Mine, adjacent to the plant.
In December 2016, Congress approved the Water Infrastructure Improvements for the Nation (WIIN) Act which authorizes the States to establish permit programs under RCRA for implementing regulation for CCR. In response to the WIIN Act and RCRA rulemaking petitions, the EPA has indicated that it intends to conduct two phases of CCR rule revisions. In July 2018, the EPA signed a Phase 1, Part 1 final rule which: (i) revised groundwater protection standards for rule-specific constituents without maximum containment levels; (ii) incorporated risk-based changes under an EPA-approved state permit program or an EPA permit program; and (iii) extended certain closure deadlines. The EPA anticipates finalizing Phase 1, Part 2 in 2019. Phase 2 is also anticipated to be finalized in 2019.

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TEP is currently working with other affected utilities and the Arizona Department of Environmental Quality to explore the possibility of developing a State administered program to enforce CCR regulation.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Management's Discussion and Analysis of Financial Condition and Results of Operations is based on our Condensed Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to apply accounting policies and make estimates, judgments, and assumptions that affect the reported amounts of assets, liabilities, net revenues and expenses, and disclosure of contingent liabilities. Management believes that there have been no significant changes during the six months ended June 30, 2018, to the items that we disclosed as our critical accounting policies and estimates in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2017 Annual Report on Form 10-K.
ACCOUNTING PRONOUNCEMENTS
For a discussion of new accounting pronouncements affecting TEP, see Note 12 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

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 can 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 2017 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES
TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13(a) – 15(e) or Rule 15(d) – 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 United States 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 persons 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 June 30, 2018.
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 quarter ended June 30, 2018, that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.


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PART II
ITEM 1. LEGAL PROCEEDINGS
For a description of certain legal proceedings affecting TEP, refer to Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS
The business and financial results of TEP are subject to numerous risks and uncertainties. As a result, the risks and uncertainties discussed in Part I, Item 1A. Risk Factors in our 2017 Form 10-K should be carefully considered. There have been no material changes in the assessment of our risk factors from those set forth in our 2017 Form 10-K.

ITEM 5. OTHER INFORMATION
RATIO OF EARNINGS TO FIXED CHARGES
 
Six Months Ended
 
Twelve Months Ended
 
June 30, 2018
 
June 30, 2018
Ratio of Earnings to Fixed Charges
3.68

 
4.58

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.


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ITEM 6. EXHIBITS
EXHIBIT INDEX
Exhibit No.
 
Description
 
Computation of Ratio of Earnings to Fixed Charges
 
 
 
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by David G. Hutchens
 
 
 
 
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act, by Frank P. Marino
 
 
 
 
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.



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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:
July 30, 2018
 
/s/ Frank P. Marino
 
 
 
Frank P. Marino
 
 
 
Vice President and Chief Financial Officer
 
 
 
(Principal Financial Officer)

 
 
 
 
 
 
 
 


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