0000100122-18-000018.txt : 20181102 0000100122-18-000018.hdr.sgml : 20181102 20181102082044 ACCESSION NUMBER: 0000100122-18-000018 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 77 CONFORMED PERIOD OF REPORT: 20180930 FILED AS OF DATE: 20181102 DATE AS OF CHANGE: 20181102 FILER: COMPANY DATA: COMPANY CONFORMED NAME: TUCSON ELECTRIC POWER CO CENTRAL INDEX KEY: 0000100122 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 860062700 STATE OF INCORPORATION: AZ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-05924 FILM NUMBER: 181155554 BUSINESS ADDRESS: STREET 1: 88 EAST BROADWAY CITY: TUCSON STATE: AZ ZIP: 85701 BUSINESS PHONE: 520-917-2644 MAIL ADDRESS: STREET 1: 88 EAST BROADWAY BLVD STREET 2: HQE809 CITY: TUCSON STATE: AZ ZIP: 85701 FORMER COMPANY: FORMER CONFORMED NAME: TUCSON GAS & ELECTRIC CO /AZ/ DATE OF NAME CHANGE: 19790528 10-Q 1 tep10q09302018.htm 10-Q 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 September 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit 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, a 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.
Large Accelerated Filer o Accelerated Filer o Non-Accelerated Filer x 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 November 1, 2018.

i




Table of Contents



ii




DEFINITIONS
The abbreviations and acronyms used in this 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
ABR
 
Alternate Base Rate
ACC
 
Arizona Corporation Commission
ACC Refund Order
 
An order issued by the ACC approving TEP’s proposal to return 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 Standards 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
LIBOR
 
London Interbank Offered Rate
LOC
 
Letter(s) of Credit
MW
 
Megawatt(s)
MWh
 
Megawatt-hour(s)
Navajo
 
Navajo Generating Station
NOI
 
Notice of Inquiry
Phase 2
 
Second phase of TEP's rate case proceedings originally filed November 2015
Phase 2 Order
 
ACC order establishing, among other things, an export rate that replaced net metering for excess solar generation
PPA
 
Power Purchase Agreement
PPFAC
 
Purchased Power and Fuel Adjustment Clause
Regional Haze
 
Regulations 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

iii




San Juan
 
San Juan Generating Station
SCR
 
Selective Catalytic Reduction
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, which includes a three-year option to purchase the unit
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



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/A; 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: voter initiatives and state and federal regulatory and legislative decisions and actions, including changes in tax and energy 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



PART I
ITEM 1. FINANCIAL STATEMENTS
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(Amounts in thousands)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Operating Revenues
$
459,760

 
$
417,210

 
$
1,089,096

 
$
1,037,736

 
 
 
 
 
 
 
 
Operating Expenses
 
 
 
 
 
 
 
Fuel
115,534

 
91,754

 
246,427

 
218,226

Purchased Power
49,564

 
38,903

 
102,317

 
107,039

Transmission and Other PPFAC Recoverable Costs
14,367

 
10,285

 
34,067

 
27,167

Increase (Decrease) to Reflect PPFAC Recovery Treatment
3,681

 
(9,166
)
 
9,087

 
(24,773
)
Total Fuel and Purchased Power
183,146

 
131,776

 
391,898

 
327,659

Operations and Maintenance
89,319

 
89,862

 
265,920

 
256,493

Depreciation
39,929

 
38,302

 
118,223

 
114,667

Amortization
6,898

 
5,463

 
18,940

 
16,323

Taxes Other Than Income Taxes
14,321

 
13,549

 
42,800

 
40,329

Total Operating Expenses
333,613

 
278,952

 
837,781

 
755,471

 
 
 
 
 
 
 
 
Operating Income
126,147

 
138,258

 
251,315

 
282,265

 
 
 
 
 
 
 
 
Other Income (Expense)
 
 
 
 
 
 
 
Interest Expense
(16,626
)
 
(16,291
)
 
(49,818
)
 
(48,972
)
Allowance For Borrowed Funds
757

 
525

 
2,150

 
1,645

Allowance For Equity Funds
2,113

 
1,353

 
5,290

 
4,145

Other, Net
1,702

 
255

 
2,957

 
8,562

Total Other Income (Expense)
(12,054
)
 
(14,158
)
 
(39,421
)
 
(34,620
)
 
 
 
 
 
 
 
 
Income Before Income Tax Expense
114,093

 
124,100

 
211,894

 
247,645

Income Tax Expense
19,120

 
42,100

 
35,521

 
83,951

Net Income
$
94,973

 
$
82,000

 
$
176,373

 
$
163,694

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 September 30,
 
Nine Months Ended September 30,
 
2018
 
2017
 
2018
 
2017
Comprehensive Income
 
 
 
 
 
 
 
Net Income
$
94,973

 
$
82,000

 
$
176,373

 
$
163,694

Other Comprehensive Income
 
 
 
 
 
 
 
Net Changes in Fair Value of Cash Flow Hedges:
 
 
 
 
 
 
 
Net of Income Tax Expense of $26 and $79
78

 
121

 
 
 
 
Net of Income Tax Expense of $99 and $212
 
 
 
 
297

 
336

Supplemental Executive Retirement Plan Adjustments:
 
 
 
 
 
 
 
Net of Income Tax Expense of $39 and $44
117

 
69

 
 
 
 
Net of Income Tax Expense of $118 and $130
 
 
 
 
349

 
209

Total Other Comprehensive Income, Net of Tax
195

 
190

 
646

 
545

Total Comprehensive Income
$
95,168

 
$
82,190

 
$
177,019

 
$
164,239

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)
 
Nine Months Ended September 30,
 
2018
 
2017
Cash Flows from Operating Activities
 
 
 
Net Income
$
176,373

 
$
163,694

Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
Depreciation Expense
118,223

 
114,667

Amortization Expense
18,940

 
16,323

Amortization of Debt Issuance Costs
1,747

 
1,763

Use of Renewable Energy Credits for Compliance
22,938

 
17,434

Deferred Income Taxes
48,056

 
83,954

Pension and Other Postretirement Benefits Expense
11,485

 
12,029

Pension and Other Postretirement Benefits Funding
(15,008
)
 
(12,763
)
Allowance for Equity Funds Used During Construction
(5,290
)
 
(4,145
)
FERC Transmission Refund Payable

 
(4,878
)
Changes in Current Assets and Current Liabilities:
 
 
 
Accounts Receivable
(57,815
)
 
(59,016
)
Materials, Supplies, and Fuel Inventory
3,749

 
452

Regulatory Assets
37

 
(2,407
)
Accounts Payable and Accrued Charges
20,959

 
25,628

Income Taxes Receivable
(12,532
)
 

Regulatory Liabilities
21,959

 
(10,258
)
Other, Net
(1,713
)
 
(5,108
)
Net Cash Flows—Operating Activities
352,108

 
337,369

Cash Flows from Investing Activities
 
 
 
Capital Expenditures
(273,398
)
 
(215,826
)
Purchase Intangibles, Renewable Energy Credits
(39,516
)
 
(40,838
)
Contributions in Aid of Construction
9,765

 
3,265

Net Cash Flows—Investing Activities
(303,149
)
 
(253,399
)
Cash Flows from Financing Activities
 
 
 
Proceeds from Borrowings, Revolving Credit Facility
101,000

 
35,000

Repayments of Borrowings, Revolving Credit Facility
(121,000
)
 
(35,000
)
Dividend Paid to Parent
(40,000
)
 
(35,000
)
Payments of Capital Lease Obligations
(10,930
)
 
(14,804
)
Other, Net
(150
)
 
641

Net Cash Flows—Financing Activities
(71,080
)
 
(49,163
)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash
(22,121
)
 
34,807

Cash, Cash Equivalents, and Restricted Cash, Beginning of Period
49,501

 
43,325

Cash, Cash Equivalents, and Restricted Cash, End of Period
$
27,380

 
$
78,132

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)
 
September 30, 2018
 
December 31, 2017
ASSETS
 
 
 
Utility Plant
 
 
 
Plant in Service
$
5,959,013

 
$
5,780,805

Utility Plant Under Capital Leases
248,635

 
84,870

Construction Work in Progress
234,994

 
160,288

Total Utility Plant
6,442,642

 
6,025,963

Accumulated Depreciation and Amortization
(2,263,742
)
 
(2,193,656
)
Accumulated Amortization of Capital Lease Assets
(70,693
)
 
(63,605
)
Total Utility Plant, Net
4,108,207

 
3,768,702

 
 
 
 
Investments and Other Property
51,339

 
51,260

 
 
 
 
Current Assets
 
 
 
Cash and Cash Equivalents
17,539

 
37,701

Accounts Receivable, Net
196,366

 
137,932

Fuel Inventory
18,666

 
25,059

Materials and Supplies
106,001

 
103,981

Regulatory Assets
110,329

 
93,960

Derivative Instruments
3,977

 
3,187

Other
26,650

 
10,777

Total Current Assets
479,528

 
412,597

Regulatory and Other Assets
 
 
 
Regulatory Assets
293,627

 
293,551

Derivative Instruments
4,910

 
8,826

Other
68,576

 
55,313

Total Regulatory and Other Assets
367,113

 
357,690

Total Assets
$
5,006,187

 
$
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)
 
September 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 September 30, 2018 and December 31, 2017)
$
1,296,539

 
$
1,296,539

Capital Stock Expense
(6,357
)
 
(6,357
)
Retained Earnings
517,327

 
380,076

Accumulated Other Comprehensive Loss
(6,458
)
 
(6,226
)
Total Common Stock Equity
1,801,051

 
1,664,032

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

 

Capital Lease Obligations
181,571

 
28,519

Long-Term Debt, Net
1,318,509

 
1,354,423

Total Capitalization
3,301,131

 
3,046,974

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

 
100,000

Borrowings Under Revolving Credit Facility
15,000

 
35,000

Capital Lease Obligations
10,713

 
10,749

Accounts Payable
130,396

 
97,367

Accrued Taxes Other than Income Taxes
62,960

 
40,706

Accrued Employee Expenses
25,346

 
30,929

Accrued Interest
14,815

 
14,750

Regulatory Liabilities
109,661

 
89,024

Customer Deposits
26,668

 
24,865

Derivative Instruments
23,822

 
10,667

Other
16,361

 
18,119

Total Current Liabilities
572,442

 
472,176

Regulatory and Other Liabilities
 
 
 
Deferred Income Taxes, Net
364,452

 
300,258

Regulatory Liabilities
494,353

 
516,438

Pension and Other Postretirement Benefits
125,339

 
133,799

Derivative Instruments
24,218

 
17,907

Other
124,252

 
102,697

Total Regulatory and Other Liabilities
1,132,614

 
1,071,099

 
 
 
 
Commitments and Contingencies

 

 
 
 
 
Total Capitalization and Other Liabilities
$
5,006,187

 
$
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, 2017
$
1,296,539

 
$
(6,357
)
 
$
380,076

 
$
(6,226
)
 
$
1,664,032

Net Income
 
 
 
 
176,373

 
 
 
176,373

Other Comprehensive Income, Net of Tax
 
 
 
 
 
 
646

 
646

Dividend Declared to Parent
 
 
 
 
(40,000
)
 
 
 
(40,000
)
Adoption of ASU, Cumulative Effect Adjustment
 
 
 
 
878

 
(878
)
 

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

 
$
(6,357
)
 
$
517,327

 
$
(6,458
)
 
$
1,801,051

 
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
 
 
 
 
163,694

 
 
 
163,694

Other Comprehensive Income, Net of Tax
 
 
 
 
 
 
545

 
545

Dividend Declared to Parent
 
 
 
 
(35,000
)
 
 
 
(35,000
)
Balances as of September 30, 2017
$
1,296,539

 
$
(6,357
)
 
$
402,102

 
$
(4,010
)
 
$
1,688,274

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

6

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 425,000 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/A.
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 September 30, 2017
 
Nine Months Ended September 30, 2017
Other Income (Deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest Income
$
30

 
$
(30
)
 
$

 
$
556

 
$
(556
)
 
$

Other Income
1,738

 
(1,738
)
 

 
12,630

 
(12,630
)
 

Other Expense
(1,072
)
 
1,072

 

 
(2,609
)
 
2,609

 

Appreciation in Value of Investments
912

 
(912
)
 

 
2,130

 
(2,130
)
 

Allowance For Equity Funds

 
1,353

 
1,353

 

 
4,145

 
4,145

Other, Net

 
255

 
255

 

 
8,562

 
8,562

 
 
 
 
 
 
 
 
 
 
 
 
Interest Expense
 
 
 
 
 
 
 
 
 
 
 
Long-Term Debt
15,531

 
(15,531
)
 

 
46,461

 
(46,461
)
 

Capital Leases
613

 
(613
)
 

 
1,941

 
(1,941
)
 

Other Interest Expense
147

 
(147
)
 

 
570

 
(570
)
 

Interest Capitalized
(525
)
 
525

 

 
(1,645
)
 
1,645

 

Allowance For Borrowed Funds

 
(525
)
 
(525
)
 

 
(1,645
)
 
(1,645
)
Interest Expense

 
16,291

 
16,291

 

 
48,972

 
48,972

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

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 September 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:
 
Nine Months Ended September 30,
(in millions)
2018
 
2017
Cash and Cash Equivalents
$
18

 
$
70

Restricted Cash included in:
 
 
 
Investments and Other Property
8

 
7

Current Assets—Other
1

 
1

Total Cash, Cash Equivalents, and Restricted Cash
$
27

 
$
78

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) and various contractual agreements. Restricted cash included in Current Assets—Other represents the current portion of TEP's share of San Juan's mine reclamation costs.
ASSET RETIREMENT OBLIGATIONS
TEP records the fair value of a liability for a legal obligation to retire a long-lived tangible asset in the period in which the liability is incurred. The Asset Retirement Obligation (ARO) accrual is primarily related to generation and photovoltaic assets and is included in Regulatory and Other Liabilities—Other on the Condensed Consolidated Balance Sheets. The following table reconciles the beginning and ending aggregate carrying amounts of ARO accruals on the Condensed Consolidated Balance Sheets:
(in millions)
Asset Retirement Obligation
Balances as of December 31, 2017
$
46

Liabilities Incurred (1)
8

Regulatory Deferral/Accretion Expense
1

Revisions to the Present Value of Estimated Cash Flows (2)
13

Balances as of September 30, 2018
$
68

(1) 
Primarily related to closure of the ash landfill at Springerville Generating Station (Springerville).
(2) 
Primarily related to changes in expected cost estimates for closure of certain generation facilities.
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

8


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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.
CompensationRetirement 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 did not have a material impact on TEP's financial statements and disclosures.
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).
Phase 2 Order
On September 20, 2018, the ACC issued an order establishing, among other things, an export rate that replaced net metering for excess solar generation (Phase 2 Order). Residential and small commercial customers who apply to interconnect their solar generation systems to TEP's distribution system after the date of the order will no longer qualify for net metering. Customers who applied before the date of the order were grandfathered under previous net metering rules for a period of 20 years from the date of interconnection of their solar generation system.
Provisions of the Phase 2 Order for new DG customers include:
an option to select from existing Time-of-Use rate schedules;

9


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



a monthly bill credit for customer solar generation exported to TEP's grid calculated using an export rate approved by the ACC; and
an annual update to the export rate based on TEP's actual solar PPA and generation facilities costs, which are expected to decline. The export rate at the time of customers' applications to interconnect will be locked for 10 years. The initial export rate was set at 9.64 cents per kilowatt-hour (kWh).
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 benefits of the TCJA through to customers. In April 2018, the ACC approved TEP’s proposal (ACC Refund Order) to return the 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, which is expected to be filed in 2019. 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. The customer bill credit will be trued-up annually to reflect actuals for kWh sales and EDIT amortization. TEP recognized a reduction in Operating Revenues on the Condensed Consolidated Statements of Income of $12 million and $29 million in the three and nine months ended September 30, 2018, respectively. TEP's regulatory liability balance related to the ACC Refund Order was $1 million as of September 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. As a result, TEP recognized a reduction in Operating Revenues on the Condensed Consolidated Statements of Income of $1 million in the nine months ended September 30, 2018. The transmission rate reduction did not have a material impact on TEP's financial position or results of operations in the three months ended September 30, 2018. 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.
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 $20 million as of September 30, 2018, and by $9 million as of December 31, 2017.

10

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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 revenues 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. In May 2018, TEP notified the ACC that it would file an application for a 2019 energy efficiency implementation plan within 60 days of the approval of the 2018 energy efficiency implementation plan.
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 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 $18 million in the three and nine months ended September 30, 2018, respectively, and $6 million and $17 million in the three and nine months ended September 30, 2017, respectively. LFCR revenues are included in Operating Revenues on the Condensed Consolidated Statements of Income.

11

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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)
 
September 30, 2018
 
December 31, 2017
Regulatory Assets
 
 
 
 
 
Pension and Other Postretirement Benefits
Various
 
$
121

 
$
126

Early Generation Retirement Costs (1)
Various
 
74

 
84

Income Taxes Recoverable through Future Rates
Various
 
43

 
40

Derivatives
3
 
42

 
18

Final Mine Reclamation and Retiree Healthcare Costs (2)
19
 
33

 
31

Lost Fixed Cost Recovery
2
 
32

 
29

Property Tax Deferrals
1
 
25

 
24

Springerville Unit 1 Leasehold Improvements (3)
5
 
12

 
14

Other Regulatory Assets
Various
 
22

 
22

Total Regulatory Assets
 
 
404

 
388

Less Current Portion
1
 
110

 
94

Total Non-Current Regulatory Assets
 
 
$
294

 
$
294

Regulatory Liabilities
 
 
 
 
 
Income Taxes Payable through Future Rates (4)
Various
 
$
346

 
$
353

Net Cost of Removal (5)
Various
 
169

 
180

Renewable Energy Standard
Various
 
52

 
44

Purchased Power and Fuel Adjustment Clause
1
 
20

 
9

Deferred Investment Tax Credits
Various
 
8

 
14

Other Regulatory Liabilities
Various
 
9

 
5

Total Regulatory Liabilities
 
 
604

 
605

Less Current Portion
1
 
110

 
89

Total Non-Current Regulatory Liabilities
 
 
$
494

 
$
516

(1) 
Includes the net book value 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 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.
(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

12

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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 September 30,
 
Nine Months Ended September 30,
(in millions)
2018
 
2017
 
2018
 
2017
Retail
$
345

 
$
334

 
$
810

 
$
801

Wholesale
79

 
44

 
152

 
116

Other Services
24

 
27

 
74

 
71

Revenues from Contracts with Customers
448

 
405

 
1,036

 
988

Alternative Revenues
5

 
6

 
20

 
19

Other
7

 
6

 
33

 
31

Total Operating Revenues
$
460

 
$
417

 
$
1,089

 
$
1,038

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 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

13

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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 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 is using 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 identifies one or more performance obligations. 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.

NOTE 4. ACCOUNTS RECEIVABLE
The following table presents the components of Accounts Receivable, Net on the Condensed Consolidated Balance Sheets:
(in millions)
September 30, 2018
 
December 31, 2017
Customer (1)
$
120

 
$
81

Customer, Unbilled
61

 
39

Due from Affiliates (Note 5)
6

 
7

Other
15

 
16

Allowance for Doubtful Accounts
(6
)
 
(5
)
Accounts Receivable, Net
$
196

 
$
138

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


14

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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)
September 30, 2018
 
December 31, 2017
Receivables from Related Parties
 
 
 
UNS Electric
$
4

 
$
5

UNS Gas
1

 
2

UNS Energy
1

 

Total Due from Related Parties
$
6

 
$
7

 
 
 
 
Payables to Related Parties
 
 
 
SES
$
2

 
$
3

UNS Energy
1

 
1

UNS Electric

 

Total Due to Related Parties
$
3

 
$
4

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

 

 
 
 
 
Transmission Revenues, UNS Electric (1)
$
2

 
$
2

 
$
5

 
$
5

Wholesale Revenues, UNS Electric (1)
1

 

 
1

 

Control Area Services, UNS Electric (2)
1

 
1

 
2

 
2

Common Costs, UNS Energy Affiliates (3)
4

 
4

 
13

 
12

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

 
4

 
11

 
11

Corporate Services, UNS Energy (5)
2

 
1

 
5

 
4

Corporate Services, UNS Energy Affiliates (6)
2

 
1

 
5

 
3

(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 $4 million for the three and nine months ended September 30, 2018, respectively, and $1 million and $3 million, for the three and nine months ended September 30, 2017, respectively.

15

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



(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.

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/A, 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)
September 30, 2018
Credit Facility
$
250

 
$
50

 
$
15

 
$
235

 
3.24
%
 
LIBOR + 1.00% 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 November 1, 2018, TEP had $205 million available under its revolving credit commitments and a Letter of Credit (LOC) facility.
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 Generating Station (Gila River) Unit 2, which includes a three-year option to purchase the unit (Tolling PPA). TEP’s obligations under the agreement were contingent upon SRP's acquisition of Gila River Units 1 and 2 from third-parties (Gila Acquisition). SRP completed the Gila Acquisition in May 2018. As a result, TEP had $164 million recorded in both Long Term LiabilitiesCapital Lease Obligations and Utility Plant Under Capital Leases on the Condensed Consolidated Balance Sheets as of September 30, 2018. The amount reflects the fair value of the unit, which was determined by SRP's purchase price. TEP anticipates exercising its option to purchase Gila River Unit 2 in December 2019 for approximately $164 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 recovers 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 September 30, 2018, capital lease obligations related to the Tolling PPA mature on the following dates:
(in millions)
Capital Lease Obligations
2018
$
3

2019
176

2020
2

2021

2022

Total 2018-2022
181

Thereafter

Less: Imputed Interest
(17
)
Total
$
164

TEP recorded $3 million and $5 million of capital lease interest in Purchased Power on the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2018, respectively, and $2 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 September 30, 2018.


16

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



NOTE 7. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
In addition to those reported in its 2017 Annual Report on Form 10-K/A, TEP entered into the following long-term commitments through September 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.
In October 2018, Westmoreland Coal Company (WCC), the owner of San Juan Coal Company’s (SJCC), filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. Public Service Company of New Mexico (PNM), the operator of San Juan, has an existing Coal Supply Agreement (CSA) with WCC to supply coal from SJCC's San Juan Mine to San Juan. TEP is not a party to the CSA, but has minimum purchase obligations under a joint participation agreement. WCC is expected to provide adequate liquidity to support continued operations at the San Juan Mine throughout the restructuring process. TEP believes it has adequate resource capacity to meet its near-term load obligations in the event WCC’s operations at the San Juan Mine are curtailed. TEP cannot currently predict the outcome of this matter or the long-term impacts on operations at San Juan.
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.
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 SJCC's 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 which was 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 $65 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 $35 million as of September 30, 2018, and $34 million as of December 31, 2017.

17

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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 September 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.

NOTE 8. EMPLOYEE BENEFIT PLANS
Net periodic benefit cost includes the following components:
 
Pension Benefits
 
Other Postretirement Benefits
 
Three Months Ended September 30,
(in millions)
2018
 
2017
 
2018
 
2017
Service Cost
$
4

 
$
3

 
$
1

 
$
1

Interest Cost
4

 
3

 
1

 
1

Expected Return on Plan Assets
(7
)
 
(6
)
 
(1
)
 
(1
)
Amortization of Net Loss
1

 
2

 

 

Net Periodic Benefit Cost
$
2

 
$
2

 
$
1

 
$
1

 
Nine Months Ended September 30,
(in millions)
2018
 
2017
 
2018
 
2017
Service Cost
$
11

 
$
9

 
$
3

 
$
3

Interest Cost
12

 
11

 
2

 
2

Expected Return on Plan Assets
(21
)
 
(18
)
 
(1
)
 
(1
)
Amortization of Net Loss
5

 
6

 

 

Net Periodic Benefit Cost
$
7

 
$
8

 
$
4

 
$
4

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

18

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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:
 
Nine Months Ended September 30,
(in millions)
2018
 
2017
Gila River Unit 2, Capital Lease
$
164

 
$

Net Cost of Removal Decrease (1)
(7
)
 
(88
)
Accrued Capital Expenditures
48

 
18

Renewable Energy Credits
3

 
4

(1) 
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.
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)
September 30, 2018
Assets
 
Cash Equivalents(1)
$
15

 
$

 
$

 
$
15

Restricted Cash(1)
10

 

 

 
10

Energy Derivative Contracts, Regulatory Recovery(2)

 
5

 

 
5

Energy Derivative Contracts, No Regulatory Recovery(2)

 

 
4

 
4

Total Assets
25

 
5

 
4

 
34

Liabilities
 
 
 
 
 
 
 
Energy Derivative Contracts, Regulatory Recovery(2)

 
(44
)
 
(4
)
 
(48
)
Total Liabilities

 
(44
)
 
(4
)
 
(48
)
Total Assets (Liabilities), Net
$
25

 
$
(39
)
 
$

 
$
(14
)

19

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



(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.
 
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)
September 30, 2018
Derivative Assets
 
 
 
 
 
 
 
Energy Derivative Contracts
$
9

 
$
6

 
$

 
$
3

Derivative Liabilities
 
 
 
 
 
 
 
Energy Derivative Contracts
(48
)
 
(6
)
 

 
(42
)
(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

20

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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 is not material to TEP's financial position or results of operations.
The table below presents realized losses recorded to Interest Expense as well as total Interest Expense on the Condensed Consolidated Statements of Income:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in millions)
2018
 
2017
 
2018
 
2017
Realized Loss From Cash Flow Hedge
$

 
$

 
$

 
$
1

Interest Expense
17

 
16

 
50

 
49

As of September 30, 2018, the total notional amount of the interest rate swap was $12 million.
Energy Derivative Contracts, Regulatory Recovery
TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in millions)
2018
 
2017
 
2018
 
2017
Unrealized Net Gain (Loss)
$
8

 
$
(1
)
 
$
(24
)
 
$
(6
)
Energy Derivative Contracts, No Regulatory Recovery
TEP enters into certain energy contracts that are considered derivatives but do not qualify for regulatory recovery. 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 table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in millions)
2018
 
2017
 
2018
 
2017
Operating Revenues
$

 
$
1

 
$
5

 
$
5


21

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Derivative Volumes
As of September 30, 2018, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:
 
September 30, 2018
 
December 31, 2017
Power Contracts GWh
2,499

 
2,589

Gas Contracts BBtu
146,612

 
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
 
Unobservable Inputs
 
Range of Unobservable Input
 
 
Assets
 
Liabilities
 
 
(in millions)
September 30, 2018
Forward Power Contracts
Market approach
 
$
4

 
$
(4
)
 
Market price per MWh
 
$
17.05

 
$
43.35

(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.
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 September 30,
 
Nine Months Ended September 30,
(in millions)
2018
 
2017
 
2018
 
2017
Beginning of Period
$
5

 
$
4

 
$
2

 
$
1

Gains (Losses) Recorded
 
 
 
 
 
 
 
Regulatory Assets or Liabilities, Derivative Instruments
1

 
1

 
1

 
3

Operating Revenues

 

 
4

 
4

Settlements
(6
)
 
(1
)
 
(7
)
 
(4
)
End of Period
$

 
$
4

 
$

 
$
4

 
 
 
 
 
 
 
 
Gains (Losses), Assets (Liabilities) Still Held
$
(2
)
 
$

 
$

 
$
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, 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

22

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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 $69 million as of September 30, 2018, compared with $27 million as of December 31, 2017. As of September 30, 2018, TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on September 30, 2018, TEP would have been required to post an additional $69 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)
 
September 30, 2018
 
December 31, 2017
 
September 30, 2018
 
December 31, 2017
Liabilities
 
 
 
 
 
 
 
 
 
Long-Term Debt, including Current Maturities
Level 2
 
$
1,466

 
$
1,466

 
$
1,484

 
$
1,547


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 September 30,
 
Nine Months Ended September 30,
(in millions)
2018
 
2017
 
2018
 
2017
Federal Income Tax Expense at Statutory Rate
$
25

 
$
44

 
$
45

 
$
87

State Income Tax Expense, Net of Federal Deduction
4

 
4

 
8

 
8

Federal/State Tax Credits
(4
)
 
(4
)
 
(7
)
 
(8
)
Excess Deferred Income Taxes
(4
)
 

 
(8
)
 

Other
(2
)
 
(2
)
 
(2
)
 
(3
)
Total Federal and State Income Tax Expense
$
19

 
$
42

 
$
36

 
$
84

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 $336 million as of September 30, 2018. See Note 2 for additional information regarding the ACC Refund Order and the FERC NOI.
Under the TCJA, Alternative Minimum Tax (AMT) credit carryforwards will be refunded if not used to offset federal income tax liabilities. As of September 30, 2018, TEP had a receivable balance of $13 million related to AMT credit carryforwards in Current Assets—Other on the Condensed Consolidated Balance Sheets.

23

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

In August 2018, the Internal Revenue Service proposed regulations on the bonus depreciation carve-out for regulated utilities. Based on the proposed regulation, the Company adjusted its estimated provision and the results did not have a material impact on TEP's financial position or results of operations. TEP's accounting for the income tax effects of the bonus depreciation provisions included in the TCJA has been completed as of September 30, 2018.

NOTE 12. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
TEP considers the applicability and impact of all Accounting Standards 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 with a lease term greater than 12 months 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 or an optional transition method with practical expedient options. The modified retrospective approach requires the restatement of prior periods and presentation of lease disclosures under the new guidance for all periods presented. The optional transition method allows entities to continue to apply the current lease guidance in the comparative periods presented in the year of adoption and apply the transition provisions of the new guidance on the effective date of the new guidance. 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 effective January 1, 2019 and will apply the transition provisions of the new standard at the adoption date. The Company expects to elect a package of practical expedients that allows it to not reassess whether any expired or existing contract is a lease or contains a lease, the lease classification of any expired or existing leases, and the initial direct costs for any existing leases. In addition, TEP will elect the practical expedient related to land easements, and the new lease guidance will be applied on a prospective basis to all new or modified land easements.
TEP’s leasing activities accounted for as operating leases primarily relate to leases for land and rail cars. 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 identifying and implementing changes to processes and controls and preparing the expanded lease disclosures. The Company does not expect the new ASU to materially affect its balance sheet, results of operations or cash flows. Management continues to monitor standard-setting activities that may affect the transition requirements of the new lease standard.
INTERNAL-USE SOFTWARE
In August 2018, the FASB issued an ASU that will clarify accounting for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers will apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The ASU also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. The standard is effective for periods beginning January 1, 2020, and should be applied either retrospectively or prospectively after the date of adoption. Early adoption is permitted. TEP plans to early adopt the new standard prospectively effective January 1, 2019 and does not expect the ASU to have a material impact on its financial statements and disclosures.


24


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 third quarter and first nine 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/A, 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 renewable 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. TEP will continue to return savings to customers through a combination of a bill credit and a regulatory liability in 2019 and through the completion of our next rate case.
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, SRP completed the Gila Acquisition. As a result, TEP had $164 million recorded in both Long Term Liabilities—Capital Lease Obligations and Utility Plant Under Capital Leases on the Condensed Consolidated Balance Sheets as of September 30, 2018, related to the 20-year Tolling PPA. The amount represents the fair value of the unit,

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which was determined by SRP's purchase price. 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.
On September 20, 2018, the ACC issued the Phase 2 Order. The order established, among other things, an initial export rate that replaced net metering for excess solar generation for customers who applied for interconnection to TEP's distribution system after the date of the order. The new rate went into effect October 1, 2018.
RESULTS OF OPERATIONS
Because weather and other factors cause seasonal fluctuations in sales of power, our quarterly results of operation are not indicative of annual results. TEP's summer peaking load occurs during the third quarter of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first quarter of the year, due to mild winter weather in our retail service territory.
The following discussion provides the significant items that affected TEP's results of operations in the third quarter and first nine months of 2018 compared with the same periods in 2017. The significant items affecting net income are presented on an after-tax basis.
The third quarter of 2018 compared with the third quarter of 2017
TEP reported net income of $95 million in the third quarter of 2018 compared with net income of $82 million in the third quarter of 2017. The increase of $13 million, or 16%, was primarily due to:
$20 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
$7 million in higher retail revenue primarily due to an increase in usage related to favorable weather.
The increase was partially offset by:
$10 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; and
$5 million in higher operations and maintenance expense resulting primarily from an increase in maintenance expense related to planned generation outages in 2018 partially offset by a decrease in employee benefits expense.
The first nine months of 2018 compared with the first nine months of 2017
TEP reported net income of $176 million in the first nine months of 2018 compared with net income of $164 million in the first nine months of 2017. The increase of $12 million, or 7%, was primarily due to:
$36 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
$16 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, and favorable weather.
The increase was partially offset by:
$24 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;
$11 million in higher operations and maintenance expense resulting primarily from an increase in maintenance expense related to planned generation outages in 2018 partially offset by a decrease in employee benefits expense; and
$5 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.

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Retail Revenues and Key Statistics
The following table provides key statistics impacting operating revenues:
 
Three Months Ended September 30,
 
Increase (Decrease)
 
Nine Months Ended September 30,
 
Increase (Decrease)
($ and kWh in millions)
2018
 
2017
 
Percent
 
2018
 
2017
 
Percent
Operating Revenues
$
460

 
$
417

 
10.3
 %
 
$
1,089

 
$
1,038

 
4.9
 %
 
 
 
 
 
 
 
 
 
 
 
 
Electric Sales (kWh)
 
 
 
 
 
 
 
 
 
 
 
Residential
1,408

 
1,361

 
3.5
 %
 
3,074

 
3,066

 
0.3
 %
Commercial
682

 
653

 
4.4
 %
 
1,683

 
1,671

 
0.7
 %
Industrial
562

 
559

 
0.5
 %
 
1,500

 
1,487

 
0.9
 %
Mining
261

 
251

 
4.0
 %
 
762

 
745

 
2.3
 %
Public Authorities
4

 
3