UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2019March 31, 2020
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)
Arizona86-0062700
(State or other jurisdiction of incorporation or organization)

(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
Securities registered pursuant to Section 12(b) of the Act: None
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. YesNo 
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  No
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 Accelerated Filer Non-Accelerated Filer Smaller Reporting Company Emerging Growth Company
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. 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
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 August 1, 2019.May 5, 2020.

i




Table of Contents

PART I
  
 
  
PART II
  


ii




DEFINITIONS
The abbreviations and acronyms used in this Form 10-Q are defined below:
INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS
2015 Credit AgreementThe 2015 Credit Agreement provides for a $250 million revolving credit and letter of credit facilities with a sublimit of $50 million; the credit agreement matures in October 2022
2019 Credit AgreementThe 2019 Credit Agreement provided for $225 million in term loans. In April 2020, the term loans were repaid and the agreement terminated
2019 ACC Rate Case A pendingIn April 2019, TEP filed a general rate case filed with the ACC by TEP in April based on a test year ended December 31, 2018
2019 requesting new rates be implemented in May 2020FERC Rate CaseIn 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings
ABRAlternate Base Rate
ACC Arizona Corporation Commission
ACC Refund Order An order issued in 2018 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 creditcredits and a regulatory liability deferral that reflects the deferral of the return of a portion of the savings, effective May 1, 2018
AFUDCADEQ Allowance for Funds Used During ConstructionArizona Department of Environmental Quality
ALJAdministrative Law Judge
AMT Alternative Minimum Tax
CAISOCOVID-19 California Independent System OperatorCoronavirus Disease 2019
DG Distributed Generation
DSM Demand Side Management
EDIT Excess Deferred Income Taxes
EE StandardsEnergy Efficiency Standards
EIMEnergy Imbalance Market
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GAAP Generally Accepted Accounting Principles in the United States of America
LFCR Lost Fixed Cost Recovery
LIBORLondon Interbank Offered Rate
LOC Letter(s) of Credit
OATT Open Access Transmission Tariff
PPA Power Purchase Agreement
PPFAC Purchased Power and Fuel Adjustment Clause
RESRenewable 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
RICE Reciprocating Internal Combustion Engine
SECSecurities and Exchange Commission
TCA Transmission Cost Adjustor
TCJA Tax Cuts and Jobs Act
TEAM Tax Expense Adjustor Mechanism
Tolling PPAA 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
VIEVariable Interest Entity
ENTITIES AND GENERATING STATIONS
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
Gila River Gila River Generating Station
Luna Luna Generating Station
Navajo Navajo Generating Station
San JuanSan Juan Generating Station

iii




Oso GrandeA 247 MW nominal capacity wind-powered electric generation facility, which is under construction in southeastern New Mexico
San JuanSan Juan Generating Station
SES Southwest Energy Solutions, Inc.
Springerville Springerville Generating Station
SRP Salt River Project Agricultural Improvement and Power District
Sundt H. Wilson Sundt Generating Station
TEP Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Tri-StateTri-State Generation and Transmission Association, Inc.
UNS Electric UNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
UNS Energy UNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy Affiliates 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
UNITS OF MEASURE
BBtu Billion British thermal unit(s), a measure of the quantity of heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit at the temperature at which water has its greatest density, in billions
GWh Gigawatt-hour(s), a measure of electricity that represents one billion watts of power expended over one hour
kWh Kilowatt-hour(s), a measure of electricity that represents one thousand watts of power expended over one hour
MW Megawatt(s)
MWhMegawatt-hour(s), a measure of electricity that represents one million watts of power


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. 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 20182019 Annual Report on Form 10-K; Part II, Item 1A. Risk Factors; Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations; and other parts of this report. These factors include: voter initiatives and state and federal regulatory and legislative decisions and actions, including changes in tax and energy policies and any change in the structure of utility service in Arizona resulting from the ACC's examination of the state's 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; the outcome of the general rate case filed with the ACC in April 2019; the outcome of the proposal filed with the FERC in May 2019 requesting revisions to TEP's OATT; regional economic and market conditions that could affect customer growth and energy usage; changes in energy consumption by retail customers; weather variations affecting energy usage; our forecasts of peak demand and whether existing generation capacity and PPAPPAs are sufficient to meet the expected demand plus reserve margin requirements; the cost of debt and equity capital and access to capital markets and bank markets, which may affect our ability to raise additional capital;capital and use the proceeds from any capital that we do raise as originally intended; 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 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; the development of our wind-powered electric generation facility in southeastern New Mexico; participation in the Energy Imbalance Market; the extent of the impact of the COVID-19 pandemic on our business and operations, and the economic and societal disruptions resulting from the COVID-19 pandemic; and the impact of the 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 June 30, Six Months Ended June 30,Three Months Ended March 31,
2019 2018 2019 20182020 2019
Operating Revenues$326,091
 $354,246
 $659,094
 $629,336
$278,556
 $333,003
          
Operating Expenses          
Fuel75,441
 62,870
 164,859
 130,893
63,299
 89,418
Purchased Power27,345
 32,389
 60,195
 52,753
18,318
 32,850
Transmission and Other PPFAC Recoverable Costs12,094
 9,909
 24,019
 19,700
10,595
 11,925
Increase (Decrease) to Reflect PPFAC Recovery Treatment(10,918) 13,372
 (4,713) 5,406
(1,182) 6,205
Total Fuel and Purchased Power103,962
 118,540
 244,360
 208,752
91,030
 140,398
Operations and Maintenance92,045
 93,445
 178,633
 176,601
87,455
 86,588
Depreciation41,427
 39,418
 82,744
 78,294
46,499
 41,317
Amortization7,397
 6,021
 15,014
 12,042
6,956
 7,617
Taxes Other Than Income Taxes14,120
 14,299
 28,321
 28,479
14,909
 14,201
Total Operating Expenses258,951
 271,723
 549,072
 504,168
246,849
 290,121
          
Operating Income67,140
 82,523
 110,022
 125,168
31,707
 42,882
          
Other Income (Expense)          
Interest Expense(22,144) (16,707) (44,275) (33,192)(20,481) (22,131)
Allowance For Borrowed Funds1,303
 706
 2,577
 1,393
2,882
 1,274
Allowance For Equity Funds3,398
 1,532
 6,721
 3,177
3,034
 3,323
Unrealized Gains (Losses) on Investments(6,427) 3,080
Other, Net842
 1,679
 4,130
 1,255
853
 208
Total Other Income (Expense)(16,601) (12,790) (30,847) (27,367)(20,139) (14,246)
          
Income Before Income Tax Expense50,539
 69,733
 79,175
 97,801
11,568
 28,636
Income Tax Expense8,476
 12,136
 10,917
 16,401
3,650
 2,441
Net Income$42,063
 $57,597
 $68,258
 $81,400
$7,918
 $26,195
The accompanying notes are an integral part of these financial statements.



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in thousands)
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
2019 2018 2019 20182020 2019
Comprehensive Income          
Net Income$42,063
 $57,597
 $68,258
 $81,400
$7,918
 $26,195
Other Comprehensive Income          
Net Changes in Fair Value of Cash Flow Hedges:          
Net of Income Tax Expense of $8 and $3224
 96
    
Net of Income Tax Expense of $17 and $73    52
 219
Net of Income Tax Expense of $0 and $9
 28
Supplemental Executive Retirement Plan Adjustments:          
Net of Income Tax Expense of $22 and $3966
 117
    
Net of Income Tax Expense of $44 and $79    132
 232
Net of Income Tax Expense of $45 and $22135
 66
Total Other Comprehensive Income, Net of Tax90
 213
 184
 451
135
 94
Total Comprehensive Income$42,153
 $57,810
 $68,442
 $81,851
$8,053
 $26,289
The accompanying notes are an integral part of these financial statements.



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in thousands)
Six Months Ended June 30,Three Months Ended March 31,
2019 20182020 2019
Cash Flows from Operating Activities      
Net Income$68,258
 $81,400
$7,918
 $26,195
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:      
Depreciation Expense82,744
 78,294
46,499
 41,317
Amortization Expense15,014
 12,042
6,956
 7,617
Amortization of Debt Issuance Costs1,153
 1,168
612
 571
Use of Renewable Energy Credits for Compliance18,624
 15,132
10,773
 8,275
Deferred Income Taxes14,244
 21,924
10,567
 4,191
Pension and Other Postretirement Benefits Expense8,881
 7,668
3,721
 4,440
Pension and Other Postretirement Benefits Funding(6,431) (5,708)(1,310) (1,744)
Allowance for Equity Funds Used During Construction(6,721) (3,177)(3,034) (3,323)
Regulatory Deferral, ACC Refund Order3,156
 
4,259
 1,707
Changes in Current Assets and Current Liabilities:      
Accounts Receivable5,910
 (41,534)29,646
 25,319
Materials, Supplies, and Fuel Inventory(4,689) 8,102
7,028
 (3,537)
Regulatory Assets(151) (5,008)(6,399) (3,400)
Other Current Assets1,766
 (1,677)2,079
 (9,449)
Accounts Payable and Accrued Charges(32,061) 16,385
(31,905) (22,687)
Income Taxes Receivable(3,326) (5,521)
Income Taxes Receivable, Net(7,185) (1,424)
Regulatory Liabilities(4,507) 17,180
3,338
 6,587
Other, Net969
 1,117
7,463
 1,078
Net Cash Flows—Operating Activities162,833
 197,787
91,026
 81,733
Cash Flows from Investing Activities      
Capital Expenditures(199,791) (174,810)(364,012) (106,279)
Purchase Intangibles, Renewable Energy Credits(24,793) (25,848)(10,625) (9,704)
Contributions in Aid of Construction3,932
 7,773
1,592
 2,852
Net Cash Flows—Investing Activities(220,652) (192,885)(373,045) (113,131)
Cash Flows from Financing Activities      
Proceeds from Borrowings, Revolving Credit Facility
 66,000
105,000
 
Repayments of Borrowings, Revolving Credit Facility
 (93,000)(20,000) 
Proceeds from Borrowings, Term Loan60,000
 
Payments of Finance Lease Obligations(10,889) (10,930)(11,535) (10,889)
Contribution from Parent150,000
 
Other, Net(166) (3)599
 383
Net Cash Flows—Financing Activities(11,055) (37,933)284,064
 (10,506)
Net Decrease in Cash, Cash Equivalents, and Restricted Cash(68,874) (33,031)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash2,045
 (41,904)
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period152,747
 49,501
28,472
 152,747
Cash, Cash Equivalents, and Restricted Cash, End of Period$83,873
 $16,470
$30,517
 $110,843
The accompanying notes are an integral part of these financial statements.


TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in thousands, except share data)
June 30, 2019 December 31, 2018March 31, 2020 December 31, 2019
ASSETS      
Utility Plant      
Plant in Service$6,126,496
 $6,020,469
$6,813,518
 $6,663,912
Utility Plant Under Finance Leases248,635
 248,635
151,467
 151,467
Construction Work in Progress298,115
 258,965
490,975
 303,488
Total Utility Plant6,673,246
 6,528,069
7,455,960
 7,118,867
Accumulated Depreciation and Amortization(2,337,169) (2,293,783)(2,537,262) (2,506,686)
Accumulated Amortization of Finance Lease Assets(79,829) (73,646)(79,722) (77,285)
Total Utility Plant, Net4,256,248
 4,160,640
4,838,976
 4,534,896
      
Investments and Other Property55,479
 50,952
54,210
 62,136
      
Current Assets      
Cash and Cash Equivalents69,692
 138,114
12,234
 9,762
Accounts Receivable, Net159,165
 172,367
Accounts Receivable (Net of Allowance for Credit Losses of $5,698 and $5,716)124,738
 154,847
Fuel Inventory26,131
 22,783
25,831
 23,731
Materials and Supplies109,331
 107,990
112,414
 121,542
Regulatory Assets118,699
 106,725
137,126
 138,412
Derivative Instruments7,216
 3,929
4,139
 3,596
Other27,131
 25,571
26,514
 21,416
Total Current Assets517,365
 577,479
442,996
 473,306
Regulatory and Other Assets      
Regulatory Assets292,068
 293,078
324,526
 326,860
Derivative Instruments11,428
 8,402
5,934
 2,763
Other85,351
 68,656
86,929
 89,196
Total Regulatory and Other Assets388,847
 370,136
417,389
 418,819
Total Assets$5,217,939
 $5,159,207
$5,753,571
 $5,489,157
The accompanying notes are an integral part of these financial statements.

(Continued)



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in thousands, except share data)
June 30, 2019 December 31, 2018March 31, 2020 December 31, 2019
CAPITALIZATION AND OTHER LIABILITIES      
Capitalization      
Common Stock Equity:      
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of June 30, 2019 and December 31, 2018)$1,346,539
 $1,346,539
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2020 and December 31, 2019)$1,546,539
 $1,396,539
Capital Stock Expense(6,357) (6,357)(6,357) (6,357)
Retained Earnings552,535
 484,277
603,710
 595,792
Accumulated Other Comprehensive Loss(4,530) (4,714)(7,636) (7,771)
Total Common Stock Equity1,888,187
 1,819,745
2,136,256
 1,978,203
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of June 30, 2019 and December 31, 2018)
 
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of March 31, 2020 and December 31, 2019)
 
Finance Lease Obligations6,192
 19,773

 67,316
Long-Term Debt, Net1,616,205
 1,615,252
1,522,326
 1,522,087
Total Capitalization3,510,584
 3,454,770
3,658,582
 3,567,606
Current Liabilities      
Current Maturities of Long-Term Debt, Net80,356
 80,330
Borrowings Under Credit Agreements, Net309,913
 165,000
Finance Lease Obligations175,202
 172,510
72,868
 17,086
Accounts Payable105,712
 133,012
99,268
 136,465
Accrued Taxes Other than Income Taxes40,499
 41,686
54,783
 42,741
Accrued Employee Expenses25,393
 34,339
20,637
 32,567
Accrued Interest17,548
 17,927
17,067
 16,700
Regulatory Liabilities89,898
 95,094
99,593
 96,017
Customer Deposits25,191
 27,650
22,512
 24,568
Derivative Instruments31,242
 18,137
21,264
 27,615
Other24,204
 21,555
24,583
 23,678
Total Current Liabilities534,889
 561,910
822,844
 662,767
Regulatory and Other Liabilities      
Deferred Income Taxes, Net390,831
 369,705
444,080
 432,484
Regulatory Liabilities497,572
 512,425
475,232
 477,495
Pension and Other Postretirement Benefits116,306
 117,472
133,937
 133,452
Derivative Instruments29,868
 19,361
51,100
 48,697
Other137,889
 123,564
167,796
 166,656
Total Regulatory and Other Liabilities1,172,466
 1,142,527
1,272,145
 1,258,784
      
Commitments and Contingencies

 


 

      
Total Capitalization and Other Liabilities$5,217,939
 $5,159,207
$5,753,571
 $5,489,157
The accompanying notes are an integral part of these financial statements.

(Concluded)



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited)
(Amounts in thousands)
 Three Months Ended
 Common Stock Capital Stock Expense Retained Earnings Accumulated Other Comprehensive Loss Total Stockholder's Equity
Balances as of March 31, 2018$1,296,539
 $(6,357) $404,757
 $(6,866) $1,688,073
Net Income    57,597
   57,597
Other Comprehensive Income, Net of Tax      213
 213
Balances as of June 30, 2018$1,296,539
 $(6,357) $462,354
 $(6,653) $1,745,883
Balances as of March 31, 2019$1,346,539
 $(6,357) $510,472
 $(4,620) $1,846,034
Common Stock Capital Stock Expense Retained Earnings Accumulated Other Comprehensive Loss Total Stockholder's Equity
Balances as of December 31, 2018$1,346,539
 $(6,357) $484,277
 $(4,714) $1,819,745
Net Income    42,063
   42,063
    26,195
   26,195
Other Comprehensive Income, Net of Tax      90
 90
      94
 94
Balances as of June 30, 2019$1,346,539
 $(6,357) $552,535
 $(4,530) $1,888,187
Balances as of March 31, 2019$1,346,539
 $(6,357) $510,472
 $(4,620) $1,846,034
 Six Months Ended
 Common Stock Capital Stock Expense Retained Earnings Accumulated Other Comprehensive Loss Total Stockholder's Equity
Balances as of December 31, 2017$1,296,539
 $(6,357) $380,076
 $(6,226) $1,664,032
Net Income    81,400
   81,400
Other Comprehensive Income, Net of Tax      451
 451
Adoption of ASU, Cumulative Effect Adjustment    878
 (878) 
Balances as of June 30, 2018$1,296,539
 $(6,357) $462,354
 $(6,653) $1,745,883
Balances as of December 31, 2018$1,346,539
 $(6,357) $484,277
 $(4,714) $1,819,745
Balances as of December 31, 2019$1,396,539
 $(6,357) $595,792
 $(7,771) $1,978,203
Net Income    68,258
   68,258
    7,918
   7,918
Other Comprehensive Income, Net of Tax      184
 184
      135
 135
Balances as of June 30, 2019$1,346,539
 $(6,357) $552,535
 $(4,530) $1,888,187
Contribution from Parent150,000
       150,000
Balances as of March 31, 2020$1,546,539
 $(6,357) $603,710
 $(7,636) $2,136,256
The accompanying notes are an integral part of these financial statements.
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 427,000432,000 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, a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis.
BASIS OF PRESENTATION
TEP's Condensed Consolidated Financial Statements and disclosures are presented in accordance with GAAP, including specific accounting guidance for regulated operations and the SEC'sSecurities 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 records its proportionate share of: (i) jointly-owned facilities in Utility Plant on the Condensed Consolidated Balance Sheets; and (ii) operating costs associated with these facilities 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 20182019 Annual Report on Form 10-K.
The Condensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair statement of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, TEP's quarterly operating results are not indicative of annual operating results.
Certain amounts from prior periods have been reclassified to conform to the current period presentation. Most notably, TEP bifurcated Other, Net on the Condensed Consolidated Statements of Income as follows:
 As Filed Amount Reclassified As Reclassified
(in thousands)Three Months Ended March 31, 2019
Other Income (Expense)     
Other, Net$3,288
 $(3,080) $208
Unrealized Gains (Losses) on Investments
 3,080
 3,080

Variable Interest Entities
TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a VIE,Variable Interest Entity (VIE), and if itTEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when it 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.
TEP routinely entershas entered into long-term renewable PPAs 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 these VIEs as it lacks the power to direct the activities that most significantly impact the economic performance of the VIEs. TEP reconsiders whether it is a primary beneficiary of the VIEs on a quarterly basis.
As of June 30, 2019,March 31, 2020, the carrying amounts of assets and liabilities inon the balance sheet that relate to variable interests under long-term PPAs are predominantly related to working capital accounts and generally represent 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 CompanyTEP would likely recover these costs through cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Restricted Cash
Restricted cash includes cash balances restricted with respect to withdrawal or usage based on contractual or regulatory considerations. The following table presents the line items and amounts of cash, cash equivalents, and restricted cash reported on the balance sheet and reconciles their sum to the cash flow statement:
Six Months Ended June 30,March 31,
(in millions)2019 20182020 2019
Cash and Cash Equivalents$70
 $6
$12
 $96
Restricted Cash included in:      
Investments and Other Property13
 9
16
 14
Current Assets—Other1
 1
3
 1
Total Cash, Cash Equivalents, and Restricted Cash$84
 $16
$31
 $111

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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 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.
NEW ACCOUNTING STANDARDS ISSUED AND ADOPTED
The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2019.2020. Unless otherwise indicated, adoption of the new guidance in each instance had an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.
LeasesCredit Losses
TEP adopted accounting guidance that requires lesseesentities to recognizeincorporate reasonable and supportable forecasts in an entity's estimates of credit losses and recognition of expected losses upon the initial recognition of a lease liability, initially measured at the present value of future lease payments,financial instrument, in addition to using past events and a right-of-use asset for all leases with a lease term greater than 12 months.current conditions. The new lease standardguidance also requires additional quantitative and qualitative disclosures regarding the activity in the allowance for both lessees and lessors. TEP appliedcredit losses for financial assets within the transition provisionsscope of the new standard as of the adoption date and did not retrospectively adjust prior periods. In addition, TEP elected a package of practical expedients that allowed it to not reassess: (i) whether existing contracts are or contain a lease; (ii) the lease classification of existing leases; or (iii) the initial direct costs for existing leases. Furthermore, TEP elected a practical expedient that permitted it to not evaluate existing land easements that were not previously accounted for as leases. The new lease guidance has been applied on a prospective basis to all new or modified land easements since January 1, 2019. Finally, TEP utilized the hindsight practical expedient in the transition provisions to determine the lease term. TEP did not identify or record an adjustment to the opening balance of retained earnings on adoption.guidance. See Note 64 for additional disclosure about TEP’s leasing arrangements.
Internal-Use Software
TEP early adopted accounting guidance that clarifies accountingTEP's allowance for implementation costs incurred in a cloud computing arrangement that is a service contract. Under the new guidance, customers apply the same criteria for capitalizing implementation costs as they would for an arrangement that has a software license. The guidance also provides specific requirements for the classification and presentation of the capitalized implementation costs and the related amortization of those costs. TEP adopted the standard prospectively.credit losses.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
New authoritative accounting guidance issued by the FASB was assessed and either determined to not be applicable or is expected to have an insignificant impact on TEP’s financial position, results of operations, cash flows, and disclosures.

NOTE 2. REGULATORY MATTERS
The ACC and the FERC each regulate portions of the utility accounting practices and rates of TEP. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect TEP's business decisions and accounting practices. The FERC regulates the termsrates and prices ofservices for electric transmission services and wholesale electricity sales.power sales in interstate commerce.
2019 ACC RATE CASE
OnIn April 1, 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018. The filing requests new rates be implemented by May 1, 2020.
TheTEP's key proposals of the rate case, adjusted for rebuttal testimony filed in November 2019, include:
a non-fuel retail revenue increase of $115$99 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $76$60 million or 7.8%, over test year retail revenues;
a 7.68%7.49% return on original cost rate base of $2.7 billion, which includes a cost of equity of 10.35%10.00% and an average cost of debt of 4.65%;

8


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



a request to recover costs of changes in generation resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the planned purchase of Gila River Unit 2 and the installation of the Sundt RICE units at Sundt;

8


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Units;
a TEAM rate that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and
a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.
Hearings before an ALJ were held in January and February 2020, and are scheduled to resume in June 2020 to address the request for inclusion of cost recovery in rates for Gila River Unit 2 and the Sundt RICE Units. As a result of work schedule disruptions arising from the COVID-19 pandemic, the timing of when new rates will go into effect is uncertain.
TEP cannot predict the outcome of the proceeding.
2019 FERC RATE CASE
On May 31,In 2019, TEP filed a proposal with the FERC requestingissued an order approving TEP's proposed OATT revisions to its OATT. The filing requests that the proposed revisions be implemented byeffective August 1, 2019.2019, subject to refund and further proceedings.
The key proposalsProvisions of the filing include:order include, but are not limited to:
replacing TEP's stated transmission rates with a forward-looking formula rate;
a 10.4% return on equity; and
elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate.
The requested forward-looking formula rate willis intended to allow for a more timely recovery of transmission related costs.
On July 31, 2019, As part of the order, the FERC issued an order accepting TEP's proposed OATT revisions effective August 1, 2019, subject to refund, and established hearing and settlement procedures. All revisions to the OATT in the FERC order are subject to refund. Settlement discussions in the proceeding are ongoing. TEP had reserved $6 million as of March 31, 2020, and $4 million as of December 31, 2019, of wholesale revenues in Current Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets. TEP cannot predict the outcome of the proceeding.
Abandoned Plant Costs
Also on May 31, 2019, TEP filed with the FERC a request to recover through its OATT rates abandoned plant costs related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that it incurred in developing the transmission line. The filing requests that the abandoned plant costs be included in TEP's transmission rate. TEP cannot predict the outcome of this proceeding. As of June 30, 2019, there was $4 million related to the Nogales transmission line recorded in Regulatory and Other Assets—Regulatory Assets on the Condensed Consolidated Balance Sheets.
FEDERAL TAX LEGISLATION
Arizona Corporation Commission
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approved TEP’s proposal to return savings from the Company’s federal corporate income tax rate under the TCJA to its customers through a combination of a customer bill creditcredits and a regulatory liability deferral that reflects the return of a portion of the savings, effective May 1, 2018.2018 (ACC Refund Order). The refundACC Refund Order represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales for the calendar year. Any over or under collected amounts are deferred to a regulatory liability or asset and will be used to adjust the following year's bill credit amounts.
The table below summarizes the regulatory asset (liability) over or under collected balance related to the ACC Refund Order:
 Three Months Ended March 31,
(in millions)2020 2019
Beginning of Period$
 $4
ACC Approved Refund (Reduction in Operating Revenues)(7) (7)
Amount Returned to Customers Through Bill Credits3
 4
Regulatory Deferral4
 2
End of Period$
 $3

Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. The 2018 refund amount totaled $33 million. TEP filed an informationinformational filing with the ACC to establish a 20192020 customer refund of $34$35 million.
The table below summarizes the regulatory asset (liability) balance relatedrefund will be returned to the ACC Refund Order:
 Three Months Ended June 30, Six Months Ended June 30,
(in millions)2019 2018 2019 2018
Beginning of Period$3
 $(7) $4
 $
ACC Refund (Reduction in Operating Revenues)(9) (10) (16) (17)
Amount Returned to Customers through Bill Credits6
 12
 10
 12
Regulatory Deferral1
 
 3
 
End of Period$1
 $(5) $1
 $(5)

customers
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



through a combination of a customer bill credit and a regulatory liability in 2020. The customer bill credit will account for 50% of the returned savings in 2020 and through the completion of our rate case. A regulatory liability balance related to the deferred TCJA customer refunds of $12 million as of March 31, 2020, and $8 million as of December 31, 2019, was recorded in Regulatory and Other Liabilities—Regulatory Liabilities on the Condensed Consolidated Balance Sheets.
COST RECOVERY MECHANISMS
TEP has received regulatory decisions that allow for more timely recovery of certain costs through the recovery mechanisms described below.
Purchased Power and Fuel Adjustment Clause
TEP's PPFAC rate is typically adjusted annually eachon April 1st and goes into effect for the subsequent 12-month period unless the schedule is modified by the ACC. The PPFAC rate includes: (i) a forward component which is calculated by taking the difference between forecasted fuel and purchased power costs and the amount of those costs established in Retail Rates; and (ii) a true-up component that reconciles the difference between actual costs and those recovered in the preceding 12-month period.
The table below summarizes the PPFAC regulatory asset (liability) balance:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(in millions)2019 2018 2019 20182020 2019
Beginning of Period$(22) $(4) $(17) $(9)$36
 $(17)
Deferred Fuel and Purchased Power Costs (1)
6
 (11) 3
 (9)48
 53
PPFAC Refunds (Recoveries) (2)
7
 (3) 5
 
PPFAC and Base Power Recoveries (2)
(48) (58)
End of Period$(9) $(18) $(9) $(18)$36
 $(22)
(1) 
The negative balance in Deferred FuelIncludes costs eligible for recovery through the PPFAC and Purchased Power Costs represents a decrease in the actual cost of fuel and purchasedbase power below the costs associated with base recoveries.rates.
(2) 
The ACC approved a PPFAC credit to begin returning the over-collected PPFAC balance to customers for the period of March 2017 through April 2018. In March 2019, the ACC approved a PPFAC credit as part of TEP's annual rate adjustment request. In March 2020, the ACC approved a PPFAC surcharge as part of TEP's annual rate adjustment request, effective June 1, 2020.
Renewable Energy Standard
The ACC’s RESRenewable Energy Standard (RES) requires Arizona regulatedArizona-regulated utilities to supply an increasing percentage of their retail sales from renewable generation sources each year. The renewable energy requirement in 2020 is 9%10% of retail electric sales, in 2019 and increaseswhich will increase annually until renewable retail sales represent at least 15% by 2025, with2025. DG accountingwill account 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 2018,2019, the ACC approved TEP's 20182019 RES implementation plan with a budget amount of $54 million, which is recovered through the RES surcharge.$55 million. The recovery funds the following:funds: (i) the above market cost of renewable power purchases; (ii) previously awarded incentives for customer-installed DG; and (iii) various other program costs.
Energy Efficiency Standards
TEP is required to implement cost-effective DSM programs to comply with the ACC’s EE Standards.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. TEP records its annual DSM performance incentive for the prior calendar year in the first quarter of each year. TEP recorded $2 million in 20192020 and 20182019 related to performance in Operating Revenues on the Condensed Consolidated Statements of Income.
In February 2019, the ACC approved TEP’s 2018 energy efficiency implementation plan with a budget of approximately $23 million, which is collected through the DSM surcharge.surcharge, and approved a waiver of the 2018 EE Standard. In addition, the ACC ordered that TEP's 2018 energy efficiency implementation plan be considered as its 2019 and 2020 energy efficiency implementation plans.
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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



occurred. TEP is required to make an annual filing with the ACC requesting recovery of LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The table below summarizes the LFCR revenues recognized in Operating Revenues on the Condensed Consolidated Statements of Income:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(in millions)2019 2018 2019 20182020 2019
LFCR Revenues$6
 $5
 $16
 $13
$12
 $10

REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities recorded onin the balance sheet are summarized in the table below:
($ in millions)
Remaining Recovery Period
(years)
 June 30, 2019 December 31, 2018
Remaining Recovery Period
(years)
 March 31, 2020 December 31, 2019
Regulatory Assets        
Pension and Other Postretirement BenefitsVarious $123
 $126
Various $133
 $135
Early Generation Retirement Costs (1)
Various 67
 72
Various 66
 68
Derivatives (Note 9)11 47
 27
10 64
 72
Income Taxes Recoverable through Future Rates (2)
Various 44
 47
Lost Fixed Cost Recovery2 42
 35
2 53
 46
Income Taxes Recoverable through Future Rates (1)
Various 37
 38
Under Recovered Purchased Energy Costs1 36
 36
Property Tax Deferrals (4)(2)
1 25
 24
Final Mine Reclamation and Retiree Healthcare Costs (3)
19 26
 29
19 21
 19
Property Tax Deferrals (4)(2)
1 24
 23
Springerville Unit 1 Leasehold Improvements (5)
4 10
 11
Springerville Unit 1 Leasehold Improvements (4)
3 8
 9
Other Regulatory AssetsVarious 28
 30
Various 19
 18
Total Regulatory Assets 411
 400
 462
 465
Less Current Portion1 119
 107
1 137
 138
Total Non-Current Regulatory Assets $292
 $293
 $325
 $327
Regulatory Liabilities   ��    
Income Taxes Payable through Future Rates (2)(1)
Various $344
 $354
Various $325
 $327
Net Cost of Removal (6)(5)
Various 162
 171
Various 159
 164
Renewable Energy StandardVarious 53
 52
Various 59
 59
Purchased Power and Fuel Adjustment Clause1 9
 17
Deferred Investment Tax Credits (7)
Various 7
 7
Deferred Investment Tax Credits (6)
Various 3
 3
Other Regulatory LiabilitiesVarious 13
 6
Various 29
 20
Total Regulatory Liabilities 588
 607
 575
 573
Less Current Portion1 90
 95
1 100
 96
Total Non-Current Regulatory Liabilities $498
 $512
 $475
 $477
(1) 
IncludesAmortized over the net book value and other related costs of Navajo and Sundt Units 1 and 2 reclassified from Utility Plant, Net on the Condensed Consolidated Balance Sheets due to the planned early retirementlives of the facilities. Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. TEP has requested recovery of final retirement costs of Navajo and Sundt Units 1 and 2 over a 10-year period in the 2019 Rate Case.assets.
(2) 
Amortized over the life of the assets. The balances include changes related to the revaluation of tax assets and liabilities as a result of the TCJA.
(3)
Represents costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners, and Navajo. TEP recognizes these costs at future value and is permitted to 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 2038.
(4)
Property taxes are recordedRecorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of property taxes on a pay-as-you-go or cash basis. TEP records a liability to reflect the accrual for financial reporting purposes and an offsetting regulatory asset to reflect recovery for regulatory purposes. This asset is fully recovered in rates with a recovery period of approximately six months.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



(5)(3)
Represents costs associated with TEP’s jointly-owned facilities at San Juan and Four Corners. TEP recognizes these costs at future value and is permitted to fully 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 2038.
(4) 
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 safe and reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year period.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



(6)(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.
(7)(6) 
Represents federal energy credits generated after 2011 that are amortized over the tax life of the underlying asset.
Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs and Springerville Unit 1 Leasehold Improvements, TEP does not earn a return on regulatory assets. Regulatory liabilities represent items that TEP either expects to pay to customers through billing reductions in future periods or plans to use for the purpose for which they were collected from customers. With the exception of over-recovered PPFAC costs and Income Taxes Payable through Future Rates, related to the EDIT balances, TEP does not pay a return on regulatory liabilities.
PLANT IN SERVICE
Under an air permit approved by the Pima County Department of Environmental Quality, TEP placed in service 5 natural gas RICE units at Sundt in December 2019 and an additional 5 units in March 2020. As of March 31, 2020 and December 31, 2019, there was $178 million and $82 million, respectively, related to the Sundt RICE Units recorded in Plant in Service on the Condensed Consolidated Balance Sheets. The 10 units have a total nominal generation capacity of 188 MW.

NOTE 3. REVENUE
DISAGGREGATION OF REVENUES
TEP earns the majority of its revenues from the sale of power to retail and wholesale customers based on regulator-approved tariff rates. The following table presents the disaggregation of TEP’s Operating Revenues on the Condensed Consolidated Statements of Income by type of service:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(in millions)2019 2018 2019 20182020 2019
Retail$236
 $273
 $438
 $465
$192
 $202
Wholesale(1)43
 35
 127
 73
36
 84
Other Services30
 27
 54
 50
24
 24
Revenues from Contracts with Customers309
 335
 619
 588
252
 310
Alternative Revenues6
 5
 18
 15
14
 12
Other11
 14
 22
 26
13
 11
Total Operating Revenues$326
 $354
 $659
 $629
$279
 $333

(1)
In 2019, the FERC issued an order approving TEP's proposed OATT revisions effective August 1, 2019, subject to refund and further proceedings. TEP began to recognize a provision for revenues subject to refund for the estimate of revenues that are probable for refund. See Note 2 for more information regarding the 2019 FERC Rate Case.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



NOTE 4. ACCOUNTS RECEIVABLE
The following table presents the components of Accounts Receivable Net on the Condensed Consolidated Balance Sheets:
(in millions)June 30, 2019 December 31, 2018
Customer (1)
$85
 $99
Customer, Unbilled59
 45
Due from Affiliates (Note 5)6
 8
Other14
 25
Allowance for Doubtful Accounts(5) (5)
Accounts Receivable, Net$159
 $172
(in millions)March 31, 2020 December 31, 2019
Retail$52
 $61
Retail, Unbilled32
 42
Retail, Allowance for Credit Losses(6) (6)
Wholesale (1)
22
 31
Due from Affiliates (Note 5)11
 8
Other14
 19
Accounts Receivable$125
 $155
(1) 
Includes $3$5 million as of June 30, 2019,March 31, 2020 and $8 million as of December 31, 2018,2019, of receivables related to revenue from derivative instruments.

Allowance for Credit Losses
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    TEP records an allowance for credit losses to reduce accounts receivable for amounts estimated to be uncollectible. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. Based on these factors, TEP has not recorded an allowance for credit losses on non-retail trade receivables as of March 31, 2020 and December 31, 2019. The following table presents the change in the balance of Retail, Allowance for Credit Losses included in Accounts Receivable on the Condensed Consolidated Balance Sheets:
 Three Months Ended
(in millions)March 31, 2020
Beginning of Period$(6)
Credit Loss Expense(1)
Write-offs1
End of Period$(6)




NOTE 5. RELATED PARTY TRANSACTIONS
TEP engages in various transactions with Fortis, UNS Energy, and the UNS Energy Affiliates. These transactions include: (i) the sale and purchase of power and transmission services; (ii) common cost allocations; and (iii) the provision of corporate and other labor relatedlabor-related services.
The following table presents the components of related party balances included in Accounts Receivable Net and Accounts Payable on the Condensed Consolidated Balance Sheets:
(in millions)June 30, 2019 December 31, 2018March 31, 2020 December 31, 2019
Receivables from Related Parties      
UNS Electric$4
 $7
$5
 $6
UNS Energy5
 
UNS Gas2
 1
1
 2
Total Due from Related Parties$6
 $8
$11
 $8
      
Payables to Related Parties      
SES$2
 $2
$4
 $2
UNS Electric2
 1
UNS Energy2
 1
1
 1
UNS Electric
 1
UNS Gas
 1
Total Due to Related Parties$4
 $5
$7
 $4
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(in millions)2019 2018 2019 20182020 2019
Goods and Services Provided by TEP to Affiliates
 
       
Transmission Revenues, UNS Electric (1)
$2
 $1
 $3
 $3
$2
 $1
Control Area Services, UNS Electric (2)
1
 1
 2
 1
1
 1
Common Costs, UNS Energy Affiliates (3)
5
 5
 10
 9
5
 5
          
Goods and Services Provided by Affiliates to TEP          
Supplemental Workforce, SES (4)
4
 4
 7
 7
4
 3
Corporate Services, UNS Energy (5)
2
 1
 3
 3
1
 1
Corporate Services, UNS Energy Affiliates (6)
1
 1
 2
 3
1
 1
Capacity Charges, UNS Gas (7)

 1
(1) 
TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable Open Access Transmission Tariff.OATT.
(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 83% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees were$1 million and $3 $2 million for the three and six months ended June 30, 2019March 31, 2020 and 2018, respectively.
2019.
(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.
(7)
UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



DIVIDENDS PAID TOCONTRIBUTION FROM PARENT
On July 22, 2019, TEP declared a $38 million dividend toApril 27, 2020, UNS Energy which wasapproved an equity contribution up to $100 million to TEP to be paid Julyon or before June 30, 2019.2020.

NOTE 6. LEASESDEBT AND CREDIT AGREEMENTS
WhenThere have been no significant changes to TEP's debt or credit agreements from those reported in its 2019 Annual Report on Form 10-K, except as noted below.
DEBT
Issuance
In April 2020, TEP issued and sold $350 million aggregate principal amount of 4.00% unsecured senior notes due June 2050. TEP may call the debt prior to December 15, 2049, with a contract conveysmake-whole premium plus accrued interest. After December 15, 2049, TEP may call the rightdebt at par plus accrued interest. TEP used the net proceeds from the sale to controlrepay amounts outstanding under its credit agreements, and intends to use the use of an identified assetremaining balance for a period of time in exchange for consideration, a right-of-use asset and lease liability are recognized. TEP measures the right-of-use asset and lease liability at the present value of future lease payments, excluding variable payments based on usage or performance. TEP calculates the present value using the rate implicit in the lease or a lease-specific secured interest rate based on the lease term. TEP has lease agreements with lease components (e.g., rent, real estate taxes and insurance costs) and nonlease components (e.g., common area maintenance costs), which are accounted for as a single lease component. TEP includes options to extend a lease in the lease term when it is reasonably certain that the option will be exercised. Leases with an initial term of twelve months or less are not recorded on the balance sheet.
TEP leases generation facilities, land, rail cars, and communication tower space with remaining terms of one to 22 years. Most leases include one or more options to renew, with renewal terms that may extend a lease term for up to 15 years. Certain lease agreements include rental payments adjusted periodically for inflation or require TEP to pay real estate taxes, insurance, maintenance, or other operating expenses associated with the lease premises.
TEP’s leases are included on the balance sheet as follows:
(in millions)Lease Type June 30, 2019
Lease Assets   
Utility Plant Under Finance LeasesFinance $249
Accumulated Amortization of Finance Lease AssetsFinance (80)
Regulatory and Other Assets, OtherOperating 8
Lease Liabilities   
Current Liabilities, Finance Lease Obligations (1)(2)
Finance 175
Finance Lease Obligations (2)
Finance 6
Current Liabilities, OtherOperating 1
Regulatory and Other Liabilities, OtherOperating 7

(1)
TEP recorded the fair value purchase price of Gila River Unit 2 as determined by SRP's 2018 purchase price. TEP expects to complete the purchase of Gila River Unit 2 in December 2019.
(2)
Springerville Common Facilities Leases consist of two leases with initial terms ending January 2021. TEP may renew the two leases or exercise its remaining fixed-price purchase options.
The following table presents the components of TEP’s lease cost:
 Three Months Ended Six Months Ended
(in millions)June 30, 2019
Finance   
Amortization of Leased Assets$3
 $6
Interest on Lease Liabilities (1)
3
 6
Operating
 1
Variable5
 9
Total Lease Cost$11
 $22
(1)
Finance lease interest expense is recorded in Interest Expense on the Consolidated Statements of Income. In 2018, lease interest expense related to Gila River Unit 2 was recorded in Purchased Power on the Consolidated Statements of Income.
TEP has a 20-year lease for energy storage with variable payments contingent on performance, which is expected to commence by the fourth quarter of 2020.general corporate purposes.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



CREDIT AGREEMENTS
2019 Credit Agreement
AsThe following table presents components of June 30,TEP's unsecured 2019 TEP hadCredit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets:
 Capacity Borrowed Available Weighted Average Interest Rate Pricing
(in millions)March 31, 2020
Term Loan$225
 $225
 $
 1.30% LIBOR + 0.550%or ABR + 0.00%

In April 2020, net proceeds from the sale of senior unsecured notes were used to repay the outstanding term loans and terminate such agreement.
2015 Credit Agreement
The following future minimum lease payments, excluding payments to lessors for variable costs:table presents components of TEP's unsecured 2015 Credit Agreement included in Borrowings Under Credit Agreements, Net on the Condensed Consolidated Balance Sheets:
(in millions)
Finance Leases (1)
 Operating Leases Total
2019$170
 $1
 $171
202020
 1
 21
2021
 1
 1
2022
 1
 1
2023
 1
 1
Thereafter
 5
 5
Total Lease Payments190
 10
 200
Less Imputed Interest9
 2
 11
Total Lease Obligations181
 8
 189
Less Current Portion175
 1
 176
Total Non-Current Lease Obligations$6
 $7
 $13
 Capacity Sub-Limit LOC 
Borrowed (1)
 Available Weighted Average Interest Rate 
Pricing (2)
(in millions)March 31, 2020
Revolver and LOC$250
 $50
 $97
 $153
 1.75% LIBOR + 1.000%or ABR + 0.00%
(1) 
Includes monthly demand charge payments$12 million in LOCs issued in January 2020 pursuant to SRP through February 2020 related to Gila River Unit 2's estimated 20-month lease term.TEP taking ownership of Oso Grande under the build-transfer agreement.
The following table presents TEP's lease terms and discount rate related to its leases:
(2)
June 30, 2019
Weighted-Average Remaining Lease Term (years)
Finance Leases1
Operating Leases12
Weighted-Average Discount Rate
Finance Leases7.1%
Operating Leases4.1%Interest rates and fees are based on a pricing grid tied to TEP's credit rating.

The following table presents TEP's cash flow information related to its leases:
 Six Months Ended
(in millions)June 30, 2019
Cash Paid for Amounts Included in the Measurement of Lease Liabilities 
Operating Cash Flows used for Finance Leases$7
Financing Cash Flows used for Finance Leases11
Right-of-Use Assets Obtained in Exchange for New Lease Liabilities 
Operating Leases8

Operating cash flows from operating leases for the six months ended June 30, 2019, were not material.
In addition, TEP leases limited office facilities and utility property to others with remaining terms of three to five years. Most leases include one or more options to renew, with renewal terms that may extend the lease term for two to ten years.
Operating lease income for the three and six months ended June 30, 2019, was not material to TEP's results of operations. TEP's expected operating lease payments to be received as of June 30, 2019, are $1 million in each of 2019 through 2023 and thereafter.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



DISCLOSURES RELATED TO PERIODS PRIOR TO ADOPTION OF THE NEW LEASE STANDARD
As of December 31, 2018, future minimum lease payments were as follows:
(in millions)Capital Leases Operating Leases
2019$187
 $1
202020
 1
2021
 1
2022
 1
2023
 1
Thereafter
 5
Total Lease Payments207
 $10
Less: Imputed Interest14
  
Total Lease Obligations193
  
Less: Current Portion173
  
Total Non-Current Lease Obligations$20
  

Operating lease cost forMay 5, 2020, there was $238 million available under the threerevolving credit commitments and six months ended June 30, 2018, was not material to TEP's results of operations.
The following table presents TEP's non-cash investing information related to its leases:
 Six Months Ended
(in millions)June 30, 2018
Assets Obtained in Exchange for New Lease Liabilities 
Capital Leases$165

In May 2018, TEP recorded an increase to both capital lease assets and liabilities related to the 20-year Tolling PPA with SRP, entered into in 2017, to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2. The Tolling PPA includes a three-year option to purchase the unit. The amount reflects the fair value of the unit as determined by SRP's purchase price.LOC facilities.

NOTE 7. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
In additionThere have been no significant changes to TEP's long-term commitments from those reported in its 20182019 Annual Report on Form 10-K, TEP entered into the following long-term commitment:
In March 2019, TEP entered into an agreement to develop a wind-powered electric generation facility with estimated costs of approximately $370 million. TEP will own and operate the facility, which will be located in southeastern New Mexico and have a nominal capacity rating of 247 MW. Construction is expected to commence in 2019 and be completed by December 2020.10-K.
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 consolidated financial results. TEP is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties, and other costs in substantial amounts 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 Reclamation and Enforcement (OSMRE) challenging several unrelated mining plan modification approvals, including two issued in 2008 related to Westmoreland San Juan Mining LLC's (as successor to San Juan Coal
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Company (SJCC)) existing San Juan Mine. The petition alleges various National Environmental Policy Act (NEPA) violations against the OSMRE, 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 OSMRE so the OSMRE 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 OSMRE'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 OSMRE released a draft EIS for public comment which was open through July 2018. On April 30, 2019, the OSMRE issued a final Record of Decision (ROD) on the Final EIS released March 15, 2019. The Final EIS contemplates continued mining at the San Juan Mine in annual quantities similar to those currently being provided through 2033. TEP plans to retire San Juan in 2022. The OSMRE's ROD is subject to approval by the Assistant Secretary for Land and Minerals Management. TEP cannot currently predict the outcome of this matter.
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 estimated share of mine reclamation costs at all three mines is $63 million. Payments will be made through the expiration of the coal supply agreements, which expire between December 2019 and 2031. An aggregate liability balance related to final mine reclamation of $36 million as of June 30, 2019 and December 31, 2018, was reflected in current and non-current Other on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.
Amounts recorded for final mine reclamation are subject to various assumptions, such as estimations of reclamation costs, the datestiming of when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP will prospectively adjustadjusts 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 classifiesdefers these costs as a regulatory assetexpenses until recovered from customers 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 out.paid.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP’s estimated share of final mine reclamation costs at both mines is $57 million upon expiration of the related coal supply agreements, which expire in 2022 and 2031, respectively. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $37 million as of March 31, 2020, and $36 million as of December 31, 2019, was recorded in Other on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to final mine reclamation costs.
Performance Guarantees
TEP has joint participation agreements with participants at Navajo, San Juan, Four Corners, and Luna. The participants in each of the generation facilities, including TEP, have guaranteed certain performance obligations. Specifically, in the event of payment default, each non-defaulting participant has agreed to bear 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 no0 maximum potential amount of future payments TEP could be required to make under the guarantees. The maximum potential amount of future payments is $250 million at Four Corners. As of June 30, 2019,March 31, 2020, there have been no0 such payment defaults under any of the participation agreements. The San Juan participation agreements expire in: (i) Decemberagreement expires in 2022, Four Corners in 2041, and Luna in 2046.
The Navajo participation agreement expired in 2019, at Navajo; (ii) 2022 at San Juan; (iii) 2041 at Four Corners; and (iv) 2046 at Luna.but certain performance obligations continue through the decommissioning of the generating station. Relative to the Navajo performance obligations, in the case of a default, the non-defaulting participants would seek financial recovery directly from the defaulting party.
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 consolidated financial results. TEP expects to recover the cost of environmental compliance from its ratepayers.customers. TEP believes it is in compliance with applicable environmental laws and regulations in all material respects.
Broadway-Pantano Site
The Water Quality Assurance Revolving Fund (WQARF) imposes liability on parties responsible for, in whole or in part, the presence of hazardous substances at a site. Those who released, generated, or disposed of hazardous substances at a contaminated site, or transported to or owned such contaminated site, are among the Potentially Responsible Parties (PRP). PRPs may be strictly liable for clean-up. The ADEQ is administering a remediation plan to delineate and then apportion costs among anticipated adverse parties in the Broadway-Pantano WQARF site, a hazardous waste site in Tucson, Arizona, which includes the Broadway North and South Landfills. Collectively, these landfills were in operation from 1953 and 1973. TEP's Eastloop Substation and a portion of a related transmission line are located on two parcels adjacent to these landfills. In November 2019, the ADEQ notified TEP that it considers TEP to be a PRP with respect to the Broadway-Pantano WQARF site. TEP does not expect this matter to have a material impact on its financial statements; however, the overall investigation and remediation plan have not been finalized.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



NOTE 8. EMPLOYEE BENEFIT PLANS
Net periodic benefit cost includes the following components:
 Pension Benefits Other Postretirement Benefits
 Three Months Ended June 30,
(in millions)2019 2018 2019 2018
Service Cost$3
 $3
 $1
 $1
Non-Service Cost (1)
       
Interest Cost5
 4
 1
 1
Expected Return on Plan Assets(7) (7) 
 
Amortization of Net Loss2
 2
 
 
Net Periodic Benefit Cost$3
 $2
 $2
 $2
Pension Benefits Other Postretirement Benefits
Six Months Ended June 30,Three Months Ended March 31,
(in millions)2019 2018 2019 20182020 2019 2020 2019
Service Cost$6
 $7
 $2
 $2
$4
 $3
 $1
 $1
Non-Service Cost (1)
              
Interest Cost9
 8
 1
 1
4
 4
 
 
Expected Return on Plan Assets(13) (14) 
 
(7) (6) 
 
Amortization of Net Loss4
 4
 
 
2
 2
 
 
Net Periodic Benefit Cost$6
 $5
 $3
 $3
$3
 $3
 $1
 $1
(1) 
The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.

NOTE 9. 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. TEP has no financial instruments categorized as Level 3.

17


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



FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS
The following tables present, by level within the fair value hierarchy, TEP’s assets and liabilities accounted for at fair value through net income 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 Total
(in millions)March 31, 2020
Assets 
Restricted Cash (1)
$18
 $
 $18
Energy Derivative Contracts, Regulatory Recovery (2)

 8
 8
Energy Derivative Contracts, No Regulatory Recovery (2)

 2
 2
Total Assets18
 10
 28
Liabilities     
Energy Derivative Contracts, Regulatory Recovery (2)

 (72) (72)
Total Liabilities
 (72) (72)
Total Assets (Liabilities), Net$18
 $(62) $(44)
Level 1 Level 2 Level 3 Total
(in millions)June 30, 2019December 31, 2019
Assets  
Cash Equivalents (1)
$67
 $
 $
 $67
Restricted Cash (1)
14
 
 
 14
$18
 $
 $18
Energy Derivative Contracts, Regulatory Recovery (2)

 10
 3
 13

 3
 3
Energy Derivative Contracts, No Regulatory Recovery (2)

 
 6
 6

 3
 3
Total Assets81
 10
 9
 100
18
 6
 24
Liabilities            
Energy Derivative Contracts, Regulatory Recovery (2)

 (48) (13) (61)
 (76) (76)
Total Liabilities
 (48) (13) (61)
 (76) (76)
Total Assets (Liabilities), Net$81
 $(38) $(4) $39
$18
 $(70) $(52)

18


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



(in millions)December 31, 2018
Assets 
Cash Equivalents (1)
$125
 $
 $
 $125
Restricted Cash (1)
15
 
 
 15
Energy Derivative Contracts, Regulatory Recovery (2)

 10
 
 10
Energy Derivative Contracts, No Regulatory Recovery (2)

 
 2
 2
Total Assets140
 10
 2
 152
Liabilities       
Energy Derivative Contracts, Regulatory Recovery (2)

 (35) (2) (37)
Total Liabilities
 (35) (2) (37)
Total Assets (Liabilities), Net$140
 $(25) $
 $115
(1) 
Cash Equivalents and Restricted Cash representrepresents amounts held in money market funds, certificates of deposit, and insured cash sweep accounts 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. In 2019, Derivative Contract Liabilities increased primarily due to increases in volume and decreases in forward market prices of natural gas.
All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis inon the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral.collateral:
Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net AmountGross 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  Counterparty Netting of Energy Contracts Cash Collateral Received/Posted 
(in millions)June 30, 2019March 31, 2020
Derivative Assets              
Energy Derivative Contracts$19
 $13
 $
 $6
$10
 $9
 $
 $1
Derivative Liabilities              
Energy Derivative Contracts(61) (13) 
 (48)(72) (9) 
 (63)
(in millions)December 31, 2018December 31, 2019
Derivative Assets              
Energy Derivative Contracts$12
 $11
 $
 $1
$6
 $4
 $
 $2
Derivative Liabilities              
Energy Derivative Contracts(37) (11) 
 (26)(76) (4) (2) (70)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



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. In addition, TEP enters into derivative and non-derivative contracts to optimize the system's generation resources by selling power in the wholesale market for the benefit of the Company's retail customers.
The CompanyTEP primarily applies the market approach for recurring fair value measurements. When TEP has observable inputs for substantially the full term of the asset or liability or uses quoted prices in an inactive market, it categorizes the instrument in Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.
For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The CompanyTEP primarily
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



uses one set of quotations each for purchased power and natural gas and then validates those prices using other sources. TEP believes that the market information provided is reflective of market conditions as of the time and date indicated.
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, TEP applies adjustments based on historical price curve relationships, transmission costs, and line losses.
TEP also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
The inputs and the Company's assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. TEP reviews the assumptions underlying its price curves monthly.
Cash Flow Hedges
To mitigate the exposure to volatility in variable interest rates on debt, TEP has an interest rate swap agreement that expires January 2020. The after-tax unrealized gains and losses on cash flow hedge activities are reported in the statement of comprehensive income. The estimated loss expected to be reclassified to earnings within the next twelve months and the realized loss recorded to Interest Expense are not material to TEP's financial position or results of operations.
As of June 30, 2019, the total notional amount of the interest rate swap was $6 million.
Energy Derivative Contracts, Regulatory Recovery
TEP enters into energy contracts that are considered derivatives and qualify for regulatory recovery. The realized gains and losses on these energy contracts are recovered through the PPFAC mechanism and the unrealized gains and losses are deferred as a regulatory asset or a regulatory liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or a regulatory liability on the balance sheet:
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended March 31,
(in millions)2019 2018 2019 20182020 2019
Unrealized Net Gain (Loss)$(11) $(14) $(20) $(32)$9
 $(9)

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 amountsDerivative revenues recorded in Operating Revenues on the Condensed Consolidated Statements of Income:
 Three Months Ended June 30, Six Months Ended June 30,
(in millions)2019 2018 2019 2018
Operating Revenues$5
 $4
 $5
 $5

Income are not material to TEP's financial position or results of operation for the three months ended March 31, 2020 and 2019.
Derivative Volumes
As of June 30, 2019,March 31, 2020, TEP had energy contracts that will settle on various expiration dates through 2029. The following table presents volumes associated with the energy contracts:
June 30, 2019 December 31, 2018March 31, 2020 December 31, 2019
Power Contracts GWh5,836
 1,743
4,118
 4,740
Gas Contracts BBtu138,837
 146,933
117,261
 122,779

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Level 3 Fair Value Measurements
The following tables provide quantitative information regarding significant unobservable inputs in TEP’sAs of March 31, 2020 and December 31, 2019, TEP did not have any Level 3 fair value measurements:
 Valuation Approach Fair Value of Unobservable Inputs Range of Unobservable Inputs
  Assets Liabilities  
(in millions)June 30, 2019
Forward Power ContractsMarket approach $9
 $(13) Market price per MWh $17.05
 $64.60
(in millions)December 31, 2018
Forward Power ContractsMarket approach $3
 $(2) Market price per MWh $16.80
 $47.05

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.
balances. 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:March 31, 2019:
 Three Months Ended
(in millions)March 31, 2019
Beginning of Period$1
Gains (Losses) Recorded 
Regulatory Assets or Liabilities, Derivative Instruments(8)
Settlements1
End of Period$(6)
  
Gains (Losses), Assets (Liabilities) Still Held$(7)
 Three Months Ended June 30, Six Months Ended June 30,
(in millions)2019 2018 2019 2018
Beginning of Period$(6) $1
 $1
 $2
Gains (Losses) Recorded       
Regulatory Assets or Liabilities, Derivative Instruments(2) 
 (10) 
Operating Revenues5
 4
 5
 4
Settlements(1) 
 
 (1)
End of Period$(4) $5
 $(4) $5
        
Gains (Losses), Assets (Liabilities) Still Held$3
 $6
 $(4) $5

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 measurements 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;limits due to the volume of trading activity; (ii) changes in natural gas or power prices; (iii) credit rating downgrades; or (iii) a failure to meet certain financial ratios.(iv) unfavorable changes in counterparties' assessment of TEP's credit strength. In the event that such credit events were to occur, the Company,TEP, or its counterparties, would have to provide certain credit enhancements in the form of cash, LOCs, or other acceptable security to collateralize exposure beyond the allowed amounts.
TEP considers the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position, after incorporating collateral posted by counterparties, and then allocates the credit risk adjustment to individual contracts. TEP also considers the impact of its credit risk on instruments that are in a net liability position, after considering the collateral posted, and then allocates the credit risk adjustment to the individual contracts.
The value of all derivative instruments in net liability positions under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $84$76 million as of June 30, 2019,March 31, 2020, compared with $41$100 million as of December 31, 2018.2019. As of June 30, 2019,March 31, 2020, TEP had no0 collateral posted with its counterparties.related to energy procurement or hedging activities. If the credit risk contingent features were triggered on June 30, 2019,March 31, 2020, TEP would have been required to post an additional $84$76 million of collateral of which $15$8 million relates to outstanding net payable balances for settled positions.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

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 dueDue to the short-term nature of these financial instruments. These itemsborrowings under revolving credit facilities approximating fair value, they 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 facenet carrying value and estimated fair value of TEP's long-term debt:
Fair Value Hierarchy Face Value Fair ValueFair Value Hierarchy Net Carrying Value Fair Value
(in millions) June 30, 2019 December 31, 2018 June 30, 2019 December 31, 2018 March 31, 2020 December 31, 2019 March 31, 2020 December 31, 2019
Liabilities                
Long-Term Debt, including Current MaturitiesLevel 2 $1,629
 $1,629
 $1,745
 $1,672
Level 2 $1,603
 $1,602
 $1,716
 $1,755




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;
factors affecting results of operations in the second quarter and first six months of 2019 compared with the same periods in 2018;operations;
factors affecting results of operations;
liquidity and capital resources, including: (i) capital expenditures; (ii) contractual obligations; and (iii) environmental matters;
critical accounting policies and estimates; and
new accounting standards issued and not yet adopted.
Management’s Discussion and Analysis includes financial information prepared in accordance with GAAP financial measures.GAAP.
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 actual future results to differ from those we currently expect or anticipate, see Forward-Looking Information at the front of this Form 10-Qreport and Risk Factors in Part 1, Item 1A of our 20182019 Annual Report on Form 10-K, and in Part II, Item 1A of this Form 10-Q.
References in this discussion and analysis to "we" and "our" are to TEP.
OUTLOOK AND STRATEGIES
TEP's financial prospectsperformance 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 and legislative actions. Our plans and strategies include:
Achieving constructive outcomes in our regulatory proceedings that will 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, affordable, and reliable service.
Continuing to focus on our long-term resource diversification strategy, including transitioning from carbon-intensive sources to a more sustainable energy portfolio, while providing reliability and 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 meetingachieving 30% of our customers’ energy needs with non-carbon emitting resources by 2030.eight years ahead of our 2030 goal. We are currently working on new long-term goals based on carbon emission reductions as part of our integrated resource plan, which we plan to file with the ACC during 2020. 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.
2019 Operational and Financial Highlights
Management's Discussion and Analysis includes the following notable items:
Entered into a build-transfer agreement to develop a 247 MW wind-power electric generation facility, which is expected to be completed by December 2020.
Filed a general rate case with the ACC based on a test year ended December 31, 2018, which includes a non-fuel retail revenue increase of $115 million.
Filed a rate case with the FERC to replace our stated transmission rates with a forward-looking formula rate. The requested forward-looking formula rate will allow for more timely recovery of transmission related costs. On July 31, 2019, FERC issued an order accepting TEP's proposed OATT revisions effective August 1, 2019, subject to refund, and established hearing and settlement procedures.

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Table of Contents

RESULTS OF OPERATIONSCURRENT ECONOMIC CONDITIONS—COVID-19
Because weatherIn March 2020, the World Health Organization declared COVID-19 a pandemic. Also in March 2020, Arizona's governor issued a declaration of a Public Health State of Emergency followed by a statewide school closure and other factors cause seasonal fluctuationstemporary closure of non-essential businesses. We are monitoring the COVID-19 pandemic and taking steps intended to mitigate the potential risks to our workforce and our business. This pandemic has disrupted economic activity in salesTEP’s service territory as well as capital markets. These disruptions could continue for a prolonged period of power,time or become severe. We are executing our quarterlybusiness continuity plans, which include actions intended to aid in the prevention of the spread of COVID-19 among our employees and customers, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. Actions we have taken include: (i) increased precautions with regard to employee and facility hygiene for field crews and others who must continue working on premise; (ii) imposed travel limitations on employees; (iii) directed employees to work remotely whenever possible; (iv) pre-work screening procedures conducted prior to entering our facilities; (v) distributed face masks to workforce; and (vi) restricted access to critical facilities. Additional safety protocols are being implemented for work required within customer premises that are intended to aid in the protection of our employees, our customers, and the community.
Recognizing the potential effect that the COVID-19 pandemic could have on many customers’ ability to pay their bills and the need for continued utility service, we temporarily suspended service disconnections and late fees for non-payment of bills until further notice. In addition, we filed a request with the ACC to refund to customers approximately $8 million of over-collected DSM funds in excess of program expenditures. The proposed refund would be in the form of a temporary reduction to the existing DSM surcharge distributed over a two-month period beginning in May 2020. We are also working with our suppliers, vendors, and contractors to assess and mitigate potential impacts to the procurement of goods and services.
The COVID-19 pandemic is a rapidly evolving situation. We cannot predict the duration of the pandemic or the ultimate effects of it on the global, national, or local economy. We will continue to monitor developments affecting our workforce, customers, suppliers, and operations and take additional measures as we believe are warranted. Through the first three months of 2020, we have not experienced a material impact to our results of operations are not indicative of annual results. TEP's summer peak load occurs during the third quarteras a result of the year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during theCOVID-19 pandemic.
Performance - 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 second quarter and first sixthree months of 20192020 compared with the same periods in 2018. The significant items affecting net income are presented on an after-tax basis.
The second quarter of2019 compared with the second quarterfirst three months of 20182019
TEP reported net income of $42$8 million in the second quarterfirst three months of 20192020 compared with net income of $58$26 million in the second quarterfirst three months of 2018.2019. The decrease of $16$18 million, or 27%70%, was primarily due to:
$1610 million in lower retail revenue primarily due to a decrease in usage relatedvalue of investments used to support certain post-employment benefits as a result of unfavorable weather;market conditions;
$34 million in higher depreciation and amortization expense due to an increase in asset base; and
$2 million in higher interest expense related to a debt issuance in November 2018.
The decrease was partially offset by:
$2 million in higher AFUDC related to an increase in construction projects.
The first six months of2019 compared with the first six monthsof2018
TEP reported net income of $68 million in the first six months of 2019 compared with net income of $81 million in the first six months of 2018. The decrease of $13 million, or 16%, was primarily due to:
$13 million in lower retail revenue primarily due to a decrease in usage related to unfavorable weather;
$6 million in higher depreciation and amortization expense due to an increase in asset base; and
$4 million in higher interest expense related to a debt issuance in November 2018.
The decrease was partially offset by:
$4 million in higher AFUDC related to an increase in construction projects;
$3 million increase in the value of company-owned life insurance as a result of favorable market conditions; and
$2 million in lowerhigher income tax expense due to the recognition of additional AMT credits related to a revision in tax law guidance.guidance in 2019 not recurring in 2020;

Operating Revenues and Key Statistics
The following table provides key statistics impacting operating revenues:
 Three Months Ended June 30, Increase (Decrease) Six Months Ended June 30, Increase (Decrease)
($ and kWh in millions)2019 2018 Percent 2019 2018 Percent
Operating Revenues$326
 $354
 (7.9)% $659
 $629
 4.8 %
            
Electric Sales (kWh)
           
Retail Sales2,105
 2,343
 (10.2)% 3,941
 4,114
 (4.2)%
Wholesale, Long-Term74
 65
 13.8 % 209
 144
 45.1 %
Wholesale, Short-Term1,606
 1,131
 42.0 % 3,653
 2,230
 63.8 %
Total Electric Sales3,785
 3,539
 7.0 % 7,803
 6,488
 20.3 %
            
Average Revenue Per kWh (Cents/kWh)
           
Retail11.21
 11.66
 (3.9)% 11.12
 11.31
 (1.7)%
Wholesale2.38
 2.92
 (18.5)% 3.17
 2.97
 6.7 %
            
Total Retail Customers    

 427,215
 424,242
 0.7 %
Operating Revenues decreased by $28$2 million in the second quarter of 2019 when compared with the same period in 2018 primarily due to: (i) lower retail sales as a result of unfavorable weather;higher operations and (ii) a decrease in fuel and purchase power recoveries as a result of lower PPFAC rates. The decrease was partially offset by an increase in short-term wholesale sales resulting from an increase in available system capacity related to Gila River Unit 2.
Operating Revenues increased by $30 million in the first six months of 2019 when compared with the same period in 2018 primarily due to an increase in short-term wholesale sales resulting from an increase in available system capacity related to Gila River Unit 2. The increase was partially offset by (i) lower retail sales as a result of unfavorable weather; and (ii) a decrease in fuel and purchase power recoveries as a result of lower PPFAC rates.
Short-term wholesale revenues are primarily related to ACC jurisdictional assets and are returned to retail customers by offsetting fuel and purchased power costs eligible for recovery through the PPFAC. Revenues related to Springerville Units 3 and 4 are primarily reimbursements by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with the corresponding expense recorded in Operating Expenses on the Condensed Consolidated Statements of Income.
Operating Expenses
Fuel and Purchased Power Expense
Fuel and Purchased Power Expense, which includes PPFAC recovery treatment, decreased by $15 million, or 12%, in the second quarter when compared with the same period in 2018. The decrease was primarily due to a decrease in: (i) recovery of PPFAC costs as a result of changes in the PPFAC rate; and (ii) price and volumes of non-renewable purchased power. The decrease was partially offset by an increase in generation output.
Fuel and Purchased Power Expense, which includes PPFAC recovery treatment, increased by $36 million, or 17%, in the first six months of 2019 when compared with the same period in 2018. The increase was primarily due to an increase in: (i) generation output; (ii) operating fees related to Gila River Unit 2; and (iii) price of non-renewable purchased power. The increases were partially offset by a decrease in recovery of PPFAC costs as a result of changes in the PPFAC rate.

The following table presents TEP’s sources of energy and average cost of power by type:
 Three Months Ended June 30, Increase (Decrease) Six Months Ended June 30, Increase (Decrease)
(kWh in millions)2019 2018 Percent 2019 2018 Percent
Sources of Energy           
Coal-Fired Generation1,606
 1,550
 3.6 % 3,372
 3,264
 3.3 %
Gas-Fired Generation1,850
 1,415
 30.7 % 3,681
 2,297
 60.3 %
Utility-Owned Renewable Generation19
 26
 (26.9)% 39
 44
 (11.4)%
Total Generation3,475
 2,991
 16.2 % 7,092
 5,605
 26.5 %
Purchased Power, Non-Renewable254
 521
 (51.2)% 674
 832
 (19.0)%
Purchased Power, Renewable205
 210
 (2.4)% 350
 365
 (4.1)%
Total Generation and Purchased Power3,934
 3,722
 5.7 % 8,116
 6,802
 19.3 %
(cents per kWh)           
Average Fuel Cost of Generated Power           
Coal2.42
 2.16
 12.0 % 2.28
 2.46
 (7.3)%
Natural Gas (1)
1.89
 1.97
 (4.1)% 2.32
 2.09
 11.0 %
Average Cost of Purchased Power           
Purchased Power, Non-Renewable2.88
 3.08
 (6.5)% 3.63
 3.02
 20.2 %
Purchased Power, Renewable9.49
 9.49
  % 9.39
 9.40
 (0.1)%
(1)
Includes realized gains and losses from hedging activity.
Operations and Maintenance Expense
There were no significant changes to Operations and Maintenance Expense in the second quarter or first six months of 2019 when compared with the same periods in 2018.
Expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, with corresponding amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income. Expenses related to customer funded renewable energy and DSM programs are collected from customers with corresponding amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income.
Depreciation and Amortization Expense
Depreciation and Amortization Expense increased by $3 million, or 7%, and $7 million, or 8%, in the second quarter and first six months of 2019, respectively, when compared with the same periods in 2018. The increases were primarily due to higher asset base.
Other Income (Expense)
Other Income (Expense) decreased by $4 million, or 30%, and $3 million, or 13%, in the second quarter and first six months of 2019, respectively, when compared with the same periods in 2018. The decreases were primarily due to an increase in interest expense related to: (i) a debt issuance in November 2018; and (ii) Gila River Unit 2 demand charges, which are recovered through the PPFAC and accounted for as finance lease interest expense. The decreases were partially offset by an increase in: (i) the value of company-owned life insurance as a result of favorable market conditions; and (ii) AFUDCmaintenance expenses related to an increase in construction projects.employee benefits expense; and
Income Tax Expense
Income Tax Expense decreased by $4$1 million or 30%, and $5 million, or 33%, in the second quarter and first six months of 2019, respectively, when compared with the same periods in 2018. The decreases weredue to lower retail revenue primarily due to a decrease in earnings before tax expense and the recognition of AMT credits in the first quarter of 2019usage related to a revisionunfavorable weather and business closures in tax law guidance.response to the COVID-19 pandemic.

The decrease was partially offset by $2 million in higher LFCR revenues.

FACTORS AFFECTING RESULTS OF OPERATIONS
Several factors affect our current and future results of operations. The most significant factors are related to the potential economic impacts of the COVID-19 pandemic, regulatory matters, generation resource diversification, and weather patterns.
COVID-19 Pandemic Impacts
The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on certain developments, including: (i) the duration of the declared health emergencies; (ii) actions being taken by governmental authorities and regulators; (iii) the impact on our customers, employees, and vendors; and (iv) actions being taken by us to assist our customers through this crisis. These developments are all rapidly evolving and challenging to predict. Areas that we currently anticipate as likely to be materially impacted and which may have an effect on our results of operations, cash flows, and earnings are noted below.
Retail Sales
As a result of the closure of non-essential businesses, stay at home orders, and economic impacts related to the COVID-19 pandemic, energy usage by our commercial customers is expected to fall below average levels experienced in prior periods. This decrease is expected to last for the duration of the pandemic response and may continue beyond as a result of sustained economic impacts in our service territory. However, we may experience an increase in residential energy usage due to widespread adoption of work from home practices. Impacts to future results of operations are expected but cannot be estimated at this time.
Timing of Regulatory Decisions
Proceedings for our pending ACC rate case have been delayed as regulators and stakeholders experience work schedule disruptions related to the COVID-19 pandemic. Our pending FERC rate case may also experience a delay related to COVID-19 work schedule disruptions. Further rate case delays may occur due to continued work schedule disruptions.
Return on Investments
We experienced a decrease in the value of investments used to support certain post-employment benefits during the first three months of 2020 as a result of unfavorable market conditions arising from the COVID-19 pandemic. Large variations in the value of investments used to support certain post-employment benefits may continue due to volatility in equity and fixed-income markets.
Retail Customer Assistance
In March 2020, we suspended service disconnections and late fees for all customers until further notice to help customers affected by the COVID-19 pandemic. We are also offering customers flexible payment extensions and payment plans. Notwithstanding current economic conditions, we did not experience a material increase in uncollectible accounts during the first three months of 2020. We will continue to assess credit loss risk and may experience an increase in bad debt expense due to the COVID-19 pandemic.
Temporary Reduction to DSM Surcharge
In April 2020, we filed a request with the ACC to refund to customers approximately $8 million of over-collected DSM funds over a two-month period beginning in May 2020. The proposed refund would be in the form of a temporary reduction to the existing DSM surcharge. We believe the proposed accelerated refund will provide more timely financial assistance to our customers.
The ACC is expected to consider this proposal and various other issues related to the COVID-19 pandemic at upcoming proceedings, including the financial impacts of the pandemic on customers and utilities. We cannot predict the timing or outcome of these proceedings.
Regulatory Matters
TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Part II, Item 7 of our 20182019 Annual Report on Form 10-K and new regulatory matters occurring in 2019.2020.

2019 ACC Rate Case
OnIn April 1, 2019, TEP filed a general rate case with the ACC based on a test year ended December 31, 2018, to provide TEP with an opportunity to recover its full cost of service, including an appropriate return on its rate base investments, and enable TEP to continue to provide safe and reliable service. The rate application is based on a test year ended December 31, 2018. We requested new rates be implemented by May 1, 2020.
TheTEP's key provisionsproposals of the rate case, adjusted for rebuttal testimony filed in November 2019, include:
a non-fuel retail revenue increase of $115$99 million, partially offset by a reduction in base fuel revenue of approximately $39 million for a net increase of $76$60 million or 7.8%, over test year retail revenues;
a 7.68%7.49% return on original cost rate base of $2.7 billion, which includes a cost of equity of 10.35%10.00% and an average cost of debt of 4.65%;
a capital structure for rate making purposes of approximately 53% common equity and 47% long-term debt;
a request to recover costs of changes in generation resource,resources, including: (i) the retirement of Navajo and Sundt Units 1 and 2; and (ii) the replacement generation capacity associated with the planned purchase of Gila River Unit 2 and the installation of the Sundt RICE units at Sundt;Units;
a TEAM rate that would be updated for income tax changes that materially affect TEP’s authorized revenue requirement; and
a TCA mechanism, updated annually, allowing TEP to recover any changes in transmission costs approved by the FERC.
TEPHearings before an ALJ were held in January and February 2020, and are scheduled to resume in June 2020 to address the request for inclusion of cost recovery in rates for Gila River Unit 2 and the Sundt RICE Units. As a result of work schedule disruptions arising from the COVID-19 pandemic, the timing of when new rates will go into effect is uncertain.
We cannot predict the outcome of thisthe proceeding.
2019 FERC Rate Case
On May 31,In 2019, TEP filed a proposal with the FERC requestingissued an order approving TEP's proposed OATT revisions to its OATT. The filing requests that the new rates be implemented byeffective August 1, 2019.2019, subject to refund and further proceedings.
The key provisionsProvisions of the filing include:order include, but are not limited to:
replacing TEP's stated transmission rates with a forward-looking formula rate;
a 10.4% rate of return on equity; and
elimination of transmission rates that are bifurcated between high-voltage and lower-voltage facilities, as well as elimination of the bifurcated loss factor rate.
The requested forward-looking formula rate willis intended to allow for a more timely recovery of transmission-related costs. If this request is approved, transmission related costs. Based on the formula rate proposed, TEP anticipates anrevenues would increase ofby approximately $7 million over current annual transmission revenue.
On July 31, 2019,annually. As part of the order, the FERC issued an order accepting TEP's proposed OATT revisions effective August 1, 2019, subject to refund, and established hearing and settlement procedures.
Abandoned Plant Costs
Also on May All revisions to the OATT in the FERC order are subject to refund. Settlement discussions in the proceeding are ongoing. TEP had reserved $6 million as of March 31, 2020, and $4 million as of December 31, 2019, TEP filed with the FERC a request to recover through its OATT rates abandoned plant costs, related to the abandoned Sahuarita, Arizona to Nogales, Arizona transmission line. TEP requested authorization to recover 100% of the approximately $9 million that TEP incurredwholesale revenues in developing the transmission line. The filing requests that the abandoned plant costs be included in TEP's transmission rate. As of June 30, 2019, there was $4 million related to the Nogales transmission line recorded in Current Liabilities—Regulatory and Other Assets—Regulatory AssetsLiabilities on the Condensed Consolidated Balance Sheets.

TEP We cannot predict the outcome of either of these proceedings.
Temporary Suspension of Residential Service Disconnection
In June 2019, the ACC adopted an emergency rule prohibiting residential service disconnections from June 1, 2019 through October 15, 2019 to address potential health risks from extreme heat. The emergency rule applies to all electric utilities in Arizona subject to ACC jurisdiction. Customers are responsible for paying past due amounts at the end of the moratorium. The ACC also initiated a comprehensive review of its disconnection rules. TEP intends to seek recovery of material costs associated with the suspension of residential service disconnections as well as the costs of complying with future changes in the ACC's disconnection rules.proceeding.
Federal Income Tax Legislation
Arizona Corporation Commission
In December 2017, the ACC opened a docket requesting that all regulated utilities submit proposals to address passing the benefits of the TCJA through to customers. In 2018, the ACC approvedissued the ACC Refund Order effective May 1, 2018.Order. The refundACC Refund Order represents the reduction in the federal corporate income tax rate and an estimate of EDIT amortization that will be trued uptrued-up annually for actuals. The bill credit was designed to return the refund amount to customers based on forecasted kWh sales.sales for the calendar year. Any over or under collected amounts are deferred to a regulatory assetliability or liabilityasset and will be used to adjust the following year's bill credit amounts.
Customer bill credits are trued-up annually to reflect actuals for both kWh sales and EDIT amortization. The refund amounts totaled $33 million in both 2019 and 2018. TEP filed an applicationinformational filing with the ACC to

establish the 2019a 2020 customer refund of $34$35 million. The refund will be returned to customers through a combination of a customer bill credit and a regulatory liability in 2019. TEP is allowed to defer 25%2020. The customer bill credit will account for 50% of the 2019 refund into a regulatory liabilityreturned savings in 2020 and 50%through the completion of any additional refunds in future years. As part of the 2019 Rate Case, we requested a TEAM that is intended to allow for the timely pass through to our customers of any income tax effects that materially impact revenue requirements as a result of federal or state income tax legislation.next rate case. TEP has proposed a TEAM to return the refundsremaining deferred in the regulatory liability account be returned to customers through the TEAM in the same year the 2019 Rate Case is completed.balance.
See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 and Liquidity and Capital Resources, Income Tax Position of this Form 10-Q for additional information regarding the ACC Refund Order.
Generation Resources
TEP’s long-term strategy is to transition to a more diverse, sustainable energy portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generation resources. Recent changes in market conditions, including lower natural gas prices and a decrease in the cost of renewables, have aided this transition. These factors, combined with increasingly stringent environmental requirements, have shifted the preference from coal as a primary fuel source to a more balanced energy portfolio of coal, natural gas, and renewable resources. Going forward, the rate and direction of change in these markets and regulatory regulation is uncertain, and the pace of our energy transition will need to adjust accordingly. These adjustments may include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for any amounts that would not otherwise be recovered as a result of these actions.
As of June 30, 2019, approximately 40% of our generation capacity, including owned and leased resources, was from coal-fired generation.
See Liquidity and Capital Resources, Environmental Matters of this Form 10-Q for additional information regarding the impact of environmental matters on generation facility operations.
Arizona Energy Policy
In 2018, the ACC opened rulemaking dockets to evaluate possible modifications to various energy policies including existing renewable energy goals, integrated resource planning, and retail competition for generation services. In July 2019 and 2020, the ACC Staff issued proposed modifications to the ACC’sstaff and two commissioners prepared different drafts of retail electric competition rules. The ACC discussedis expected to discuss those draft rules on July 30, 2019, as part of a scheduled workshop.during upcoming workshops, but such rules have not been officially proposed and no changes have been made. We anticipate that the ACC will hold additional workshops related to retail electric competition and other energy-related policies. The adoption of new policies or rules would be subject to rulemaking proceedings at the ACC. We would seek the ACC's approval to recover any costs related to new energy policies or requirements. TEP cannot predict the outcome of these matters or its impact on the Company's financial position or results of operations.

Generation Resource Diversification
TEP’s long-term strategy is to shift to a more diverse, sustainable energy portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generation resources. TEP's existing coal-fired generation fleet faces a number of uncertainties impacting the viability of continued operations, including changing state and federal law and energy policies, competition from other resources, fuel supply and land lease contract extensions, environmental regulations, and, for jointly owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, TEP may consider options that include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions.
As of March 31, 2020, approximately 37% of our generation capacity was from coal-fired generation.
See Liquidity and Capital Resources, Environmental Matters of this Form 10-Q for additional information regarding generation facility operations.
Navajo Generating Station
In 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations throughretired the generation station in November 2019 and beginbegan decommissioning activities. TEP expects the majority of decommissioning activities thereafter. Navajoto be completed by 2024 with monitoring activities continuing through 2054. TEP is expected to shut down on or before December 22, 2019. We are currently recovering Navajo'sthe capital and operating costs in base rates using a useful life through 2030.of 2030 for Navajo. Due to the early retirement, of Navajo, in the 2019 Rate Case we haveTEP requested recovery of final retirement costs over a 10-year period.period in the 2019 ACC Rate Case. As of June 30, 2019,March 31, 2020, the net book value of Navajo was $41$42 million, with estimated other related costs of $4 million.
See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the planned early retirement of Navajo.
Sundt Generating Station
In 2017, TEP submitted an Air Quality Permit Application to2018, the Pima County Department of Environmental Quality relatedapproved TEP's air permit, which allowed TEP to a generation modernization project at Sundt. Under the project, TEP will place in service 10 natural gas RICE units at Sundt and required the retirement of Sundt Units 1 and 2 in November 2019. TEP is currently recovering the capital and operating costs in base rates using useful lives of 2028 and 2030 of Sundt Units 1 and 2, respectively. Due to the early retirement, TEP requested recovery of final retirement costs over a 10-year period in the 2019 ACC Rate Case. As of March 31, 2020, the net book value of Sundt Units 1 and 2 was $25 million, with a total nominal generation capacityestimated other related costs of 190 MW. The final permit was issued$1 million.
TEP placed in December 2018. Construction is underway withservice five of the RICE units scheduled for commercial operation byin December 2019, and the end of the first quarter ofremaining five were placed in service in March 2020. We have requested recovery of theThe Sundt RICE project costs in the 2019 Rate Case.
The RICE units willUnits balance the variability of intermittent renewable energy resources and will replaceresources. The units replaced 162 MW of nominal net generation capacity from Sundt Units 1 and 2, which arewere less efficient and lacklacked the quick start, fast ramp capabilities of the Sundt RICE units.Units. TEP will discontinue operation of Sundt Units 1 and 2 prior to start-up of the first RICE unit. We are currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives through 2028 and 2030, respectively. Due to the early retirement of Sundt Units 1 and 2, we have requested recovery of final retirement coststhe 10 Sundt RICE Units over a 10-year periodthe useful lives of the assets in the 2019 ACC Rate Case. AsThe total cost of June 30, 2019, the net book value of Sundt RICE Units 1 and 2project was $27 million, with estimated other related costs of $1$178 million.
See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the planned early retirement of Sundt Units 1 and 2.
Gila River Generating Station
In 2017, TEP entered into a 20-year tolling PPA with SRP to purchase and receive all 550 MW of capacity, power, and ancillary services from Gila River Unit 2, which includesincluded a three-year option to purchase Gila River Unit 2 (Tolling PPA).the unit. TEP anticipates completingcompleted the purchase of Gila River Unit 2 in December 2019 for approximately $164$165 million. The 550 MW of capacity, power, and ancillary services replaced coal-fired

generation lost due to early retirements. We have requested recovery of the Gila River Unit 2 purchase over the remaining useful life of the asset in the 2019 ACC Rate Case.
Executive Order
On May 1, 2020, the President of the United States of America signed an Executive Order, Securing the United States Bulk-Power System. We are currently evaluating the potential impacts of this Executive Order.
Production Tax Credits
Federal renewable electricity Production Tax Credits (PTC) are earned as energy from qualifying wind-powered generating facilities is produced and sold based on a per kilowatt rate as prescribed pursuant to the applicable federal income tax law. Qualifying generating facilities are eligible for the credit for 10 years from the date the facilities are placed in service. The PTC rate is published annually by the IRS and was $0.025 per kWh produced and sold for 2019. TEP will continue to pay a monthly demand charge consisting of: (i) a fixed capacity chargebegin earning PTCs once Oso Grande begins producing and selling power.
Weather Patterns
Weather and other factors cause seasonal fluctuations in the sales of approximately $1 million, and (ii) an operating fee to compensate SRP for the non-fuel costs of operating Gila River Unit 2 until the purchase is complete. TEP recovers the monthly demand charge through the PPFAC mechanism.
We expect the additional 550 MW of capacity, power, and ancillary services from the Tolling PPA to allow us to continue to move toward our long-term goal of resource diversification as it will replace coal-fired generation scheduled for early retirement. TEP sells the capacity from the Tolling PPA into the wholesale market on a short-term basis with the associated revenues credited to the PPFAC.
Renewable Generating Facility
In March 2019, TEP entered into an agreement to develop a wind-powered electric generation facility with estimated costs of approximately $370 million. TEP will own and operate the facility, which will be located in southeastern New Mexico and have a nominal capacity rating of 247 MW. Construction is expected to commence bypower. TEP's summer peaking load occurs during the third quarter of 2019 and be completed by December 2020. The wind projectthe year when cooling demand is expected to qualify forhigher, which results in higher revenue during such period. By contrast, lower sales of power occur during the IRS renewable Production Tax Credit. The credit is expected to recover a minimum of $250 millionfirst quarter of the project's costsyear, due to mild winter weather in our retail service territory. Seasonal fluctuations affect the first 10 years and the remaining portioncomparability of the credit after the date the facility is placed in service.
Energy Imbalance Market
In May 2019, TEP signed an agreement with the CAISO and plans to begin participating in the EIM by April 2022. The EIM is expected to reduce costs to serve customers through more efficient dispatchour results of a larger and more diverse pool of resources, more effectively integrate renewables, and enhance reliability through improved system utilization and responsiveness.

operations.
Interest Rates
See Part II, Item 7A in our 20182019 Annual Report on Form 10-K and Part II,I, Item 3 of this Form 10-Q for information regarding interest rate risks and its impact on earnings.
RESULTS OF OPERATIONS
Significant drivers of TEP's results of operations that do not have a significant impact on net income include:
Cost Recovery Mechanisms — TEP records operating revenue related to cost recovery mechanisms that allow for more timely recovery of fuel and purchase power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, Renewable Energy Standard Tariff, and DSM, are generally reset annually through separate filings with the ACC. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on cost recovery mechanisms.
Short-Term Wholesale Sales — Revenues related to short-term wholesale sales are primarily related to ACC jurisdictional generation assets and are returned to retail customers by offsetting revenues against fuel and purchased power costs eligible for recovery through the PPFAC cost recovery mechanism.
Springerville Units 3 and 4 — Operations and maintenance expenses related to Springerville Units 3 and 4 are reimbursed by Tri-State Generation and Transmission Association, Inc., the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, through participant billings recorded in Operating Revenues on the Condensed Consolidated Statements of Income.
The following discussion provides the significant items that affected TEP's results of operations in the first three months of 2020 compared with the same period in 2019 presented on a pre-tax basis.

Operating Revenues
The following table provides a disaggregation of Operating Revenues:
 Three Months Ended March 31, Increase (Decrease)
(in millions)2020 2019 Percent
Operating Revenues     
Retail$192
 $202
 (5.0)%
Wholesale, Long-Term7
 9
 (22.2)%
Wholesale, Short-Term (1)
29
 72
 (59.7)%
Transmission7
 8
 (12.5)%
Springerville Units 3 and 4 Participant Billings20
 20
  %
Other24
 22
 9.1 %
Total Operating Revenues$279
 $333
 (16.2)%
(1)
Revenues associated with derivatives are primarily passed back to retail customers by offsetting the fuel and purchase power costs eligible for recovery through the PPFAC mechanism similar to short-term wholesale sales. As a result, revenues associated with derivatives are included in Wholesale, Short-Term in the table above.
TEP reported operating revenues of $279 million in the first three months of 2020 compared with $333 million in the same period for 2019. The decrease of $54 million, or 16%, was primarily due to:
$43 million in lower wholesale short-term sales primarily due to a decrease in (i) volumes driven by the expiration of a capacity sale contract in December 2019; and (ii) pricing as a result of unfavorable market conditions; and
$10 million in lower retail revenue primarily due to lower fuel and purchase power recoveries as a result of lower PPFAC rates.
The decrease was partially offset by a $2 million increase in other revenues primarily due to higher LFCR revenue.
The following table provides key statistics impacting operating revenues:
 Three Months Ended March 31, Increase (Decrease)
(kWh in millions)2020 2019 Percent
Electric Sales (kWh) (1)
     
Retail Sales1,800
 1,836
 (2.0)%
Wholesale, Long-Term72
 135
 (46.7)%
Wholesale, Short-Term1,246
 2,047
 (39.1)%
Total Electric Sales3,118
 4,018
 (22.4)%
      
Average Revenue Per kWh (Cents/kWh) (2)
     
Retail10.67
 11.02
 (3.2)%
Wholesale, Long-Term10.04
 6.72
 49.4 %
Wholesale, Short-Term2.30
 3.57
 (35.6)%
      
Total Retail Customers (3)
431,691
 426,756
 1.2 %
(1)
These numbers represent the kWh sold to retail, long-term wholesale, and short-term wholesale customers. Management uses kWh sold to retail and wholesale customers to monitor electricity usage.
(2)
This metric represents the cents earned per kWh for retail and wholesale revenue. This number is calculated as revenue divided by Electric Sales (kWh) for each respective revenue class. Management uses this metric to monitor retail and wholesale rates.
(3)
This number represents the total retail customer count across all customer classes including residential, commercial, industrial (mining), industrial (non-mining), and other. The customer count is based on the number of active service agreements at the end of each period. Management uses this count to monitor the growth of retail customers.

Operating Expenses
Fuel and Purchased Power Expense
TEP reported fuel and purchased power expense of $91 million in the first three months of 2020 compared with $140 million in the same period for 2019. The decrease of $49 million, or 35%, was primarily due to:
$26 million in lower fuel costs primarily due to a decrease in natural gas prices and a decrease in Coal and Gas-Fired Generation volumes;
$15 million in lower purchased power primarily due to a decrease in volume and the purchase of Gila River Unit 2; and
$7 million in lower PPFAC recoveries primarily due to changes in the PPFAC rate.
The following provides key statistics impacting fuel and purchase power:
 Three Months Ended March 31, Increase (Decrease)
(kWh in millions)2020 2019 Percent
Sources of Energy     
Coal-Fired Generation1,409
 1,766
 (20.2)%
Gas-Fired Generation1,476
 1,832
 (19.4)%
Utility-Owned Renewable Generation20
 20
  %
Total Generation2,905
 3,618
 (19.7)%
Purchased Power, Non-Renewable170
 420
 (59.5)%
Purchased Power, Renewable151
 144
 4.9 %
Total Generation and Purchased Power (1)
3,226
 4,182
 (22.9)%
(cents per kWh)     
Average Fuel Cost of Generated Power (2)
     
Coal2.53
 2.16
 17.1 %
Natural Gas (3)
1.80
 2.75
 (34.5)%
Average Cost of Purchased Power (4)
     
Purchased Power, Non-Renewable2.59
 4.08
 (36.5)%
Purchased Power, Renewable9.31
 9.25
 0.6 %
(1)
This number represents the kWh generated from TEP's generating stations including coal-fired, gas-fired, and renewable generation, combined with the kWh of purchased power from both renewable and non-renewable sources. Management uses this number to monitor the performance of each energy source.
(2)
This metric represents the fuel cost as cents per kWh for coal and natural gas generated power. This number is calculated as fuel cost divided by Generation (kWh) for each respective generation source. Management uses this metric to monitor rates and pricing as well as analyze the performance of generation stations.
(3)
Includes realized gains and losses from hedging activity.
(4)
This metric represents the fuel cost as cents per kWh for renewable and non-renewable purchased power. This number is calculated as purchased power cost divided by Purchased Power (kWh) for each respective form of purchased power. Management uses this metric to compare and monitor the costs of renewable and non-renewable purchased power.

Operations and Maintenance Expense
TEP reported operations and maintenance expense of $87 million in the first three months of 2020 compared with $87 million in the same period for 2019, an increase of less than $1 million, or 1%. The increase was primarily due to $2 million in increased employee benefits expense. The increase was partially offset by $2 million in lower expenses related to Springerville Units 3 and 4 due to planned outages in 2019 not recurring in 2020.
Depreciation and Amortization Expense
Depreciation and amortization expense increased by $5 million, or 9%, in the first three months of 2020 compared with the same period in 2019 primarily due to an increase in asset base.
Other Income (Expense)
TEP reported other expense of $20 million in the first three months of 2020 compared with $14 million in the same period for 2019. The increase of $6 million, or 43%, was primarily due to a $10 million decrease in the value of investments used to support certain post-employment benefits as a result of unfavorable market conditions.
The increase was partially offset by:
$2 million in lower finance lease interest expense due to the purchase of Gila River Unit 2 in December 2019;
$1 million increase in other income due to an increase in expected return on pension plan assets; and
$1 million in higher Allowance for Funds Used During Construction due to an increase in construction projects.
Income Tax Expense
TEP reported tax expense of $4 million in the first three months of 2020 compared with $2 million in the same period for 2019. The increase of $2 million, or 100%, was primarily due to:
$2 million in lower tax credits related to AMT credits recognized in the first quarter of 2019 not recurring in 2020; and
$1 million in higher plant flow through and EDIT amortization.
The increase was partially offset by $2 million in lower tax expense due to a decrease in taxable earnings.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
CashThe COVID-19 pandemic has negatively impacted the global economy and created significant volatility and disruption of financial markets. An extended period of economic disruption could negatively affect our business and financial condition, and access to sources of liquidity. In addition, cash flows may vary during the year with cash flows from operations typically being typically the lowest in the first quarter of the year and highest in the third quarter due to TEP's summer peaking load. We use our revolving credit facility as needed to assist in fundingfund our business activities. We believe thatBased on our expectations, including possible impacts of COVID-19 on sales, accounts receivable collections, and capital spending, we have sufficient liquidity under our revolving credit facility to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements.anticipate the need for external financing in the third or fourth quarter of 2020. The availability and terms under which we have access to external financing depends on a variety of factors, including our credit ratings and conditions in the overallbank and capital markets.
Available Liquidity
(in millions)June 30, 2019March 31, 2020
Cash and Cash Equivalents$70
$12
Amount Available under Revolving Credit Facility (1)
250
Amount Available under Revolving Credit Agreement (1)
153
Total Liquidity$320
$165
(1) 
TEP's revolving credit facilityThe 2015 Credit Agreement provides for $250 million of revolving credit commitments with a LOC sublimit of $50 million and a maturity date of October 2022.

Future Liquidity Requirements
We expect to meet all of our financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include, but are not limited to: (i) dividend payments; (ii) debt maturities; and (iii) obligations included in the Contractual Obligations and forecasted Capital Expenditures tables reported in our 20182019 Annual Report on Form 10-K and the material changes summarized below in the respective sections.
Summary of Cash Flows
The table below presents net cash provided by (used for) operating, investing and financing activities:
Six Months Ended June 30, Increase (Decrease)Three Months Ended March 31, Increase (Decrease)
(in millions)2019 2018 Percent2020 2019 Percent
Operating Activities$163
 $198
 (17.7)%$91
 $82
 11.0 %
Investing Activities(221) (193) 14.5 %(373) (113) 230.1 %
Financing Activities(11) (38) (71.1)%284
 (11) *
Net Increase (Decrease)(69) (33) 109.1 %2
 (42) (104.8)%
Beginning of Period153
 50
 206.0 %28
 153
 (81.7)%
End of Period (1)
$84
 $17
 394.1 %$30
 $111
 (73.0)%
* Not meaningful
(1) 
Calculated on rounded data and may not correspond exactly to amounts on the Condensed Consolidated Statements of Cash Flows.
Operating Activities
In the first sixthree months of 2019,2020, net cash flows from operating activities decreasedincreased by $35$9 million compared with the same period in 2018.2019. The decreaseincrease was primarily due to: (i) lower retail sales as$10 million of collateral posted to a result of unfavorable weather;counterparty for a credit enhancement in 2019 not occurring in 2020; and (ii) a decrease in recovery of PPFAC costs as a result of changes in the PPFAC rate; and (iii) changes in working capital related to the timing of collectionscollections. The increase was partially offset by lower retail revenue primarily due to: (i) lower fuel and payments.purchase power recoveries as a result of lower PPFAC rates; and (ii) lower customer usage due to unfavorable weather and impacts of the COVID-19 pandemic.
Investing Activities
In the first sixthree months of 2019,2020, net cash flows used for investing activities increased by $28$260 million compared with the same period in 20182019 primarily due to an increase in cash paida payment of $226 million for capital expenditures in 2019.

the Oso Grande project under the build-transfer agreement.
Financing Activities
In the first sixthree months of 2019,2020, net cash flows used forfrom financing activities decreasedincreased by $27$295 million compared with the same period in 20182019 primarily due to a decreaseto: (i) an increase in repayments,equity contributions from UNS Energy; and (ii) higher proceeds from credit facility borrowings, net of proceeds borrowed, under our revolving credit facility in 2018.
TEP anticipates raising additional capital in the second half of 2019 to: (i) finance the purchase of Gila River Unit 2; (ii) make payments for the development of a wind-powered electric generation facility; and (iii) repay any borrowings under our revolving credit facility, with any remaining balance to be applied to general corporate purposes.repayments.
Sources of Liquidity
Short-Term Investments
Our short-term investment policy governs the investment of excess cash balances. We periodically review and update this policy in response to market conditions. As of June 30, 2019, TEP'sMarch 31, 2020, TEP had no short-term investments included highly-rated and liquid money market funds and insured cash sweep accounts.investments.
Access to Revolving Credit FacilityAgreements
We have access to working capital through a revolvingour credit agreement with lenders. TEP expects that amountsagreements.
Amounts borrowed from the 2019 Credit Agreement were used (i) to complete the purchase of Gila River Unit 2 Generating Station; (ii) to make payments for the construction of the Oso Grande project; and (iii) for other general corporate purposes. As of March 31, 2020, there was no amount available under the credit facility2019 Credit Agreement. In April 2020, net proceeds from the sale of senior unsecured notes were used to repay the 2019 Credit Agreement's outstanding term loan and terminate such agreement.
Amounts borrowed from the 2015 Credit Agreement will be used for working capital and other general corporate purposes and that LOCs will be issued from time to time to support energy procurement, hedging transactions, and hedging transactions.other business activities. As of June 30, 2019,

March 31, 2020, there was $250$153 million available under the revolving credit commitments and2015 Credit Agreement. As of May 5, 2020, there was $238 million available under the LOC facility.2015 Credit Agreement.
See Note 7 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 20182019 Annual Report on Form 10-K for additional information regarding TEP's credit facilityagreements.
Debt Financing
We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. We are exposed to adverse changes in interest rates to the extent that we rely on variable rate financing. Our cost of capital is also affected by our credit ratings.
On February 14, 2020, TEP filed a financing application with the ACC. The application requests extending and expanding the existing financing authority by: (i) extending authority from December 2020 to December 2025; (ii) increasing the outstanding long-term debt limitation from $2.2 billion to $2.9 billion; (iii) allowing parent equity contributions of up to $700 million; and (iv) continuing the interest rate hedging authority.
In April 2020, we issued and sold $350 million aggregate principal amount of senior unsecured notes to repay: (i) $225 million of outstanding borrowings under our 2019 Credit Agreement, which we terminated; and (ii) outstanding borrowings under our 2015 Credit Agreement, and intend to use the remaining balance for general corporate purposes.
TEP has, from time to time, refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, we may refinance other debt issuances or make additional debt repurchases in the future.
In 2016, the ACC issued an order granting TEP financing authority. The order extends and expands the previous financing authority by: (i) extending authority from December 2016 to December 2020; (ii) increasing the outstanding long-term debt limitation from $1.7 billion to $2.2 billion; (iii) allowing parent equity contributions of up to $400 million; and (iv) continuing the interest rate hedging authority.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. As of June 30, 2019,March 31, 2020, credit ratings from S&P Global Ratings and Moody’s Investors Service for our senior unsecured debt were A- and A3, respectively.
Our credit ratings are dependentdepend on a number of factors, both quantitative and qualitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell, or hold TEP securities. Each rating should be evaluated independently of any other ratings.
Our credit agreement containsCertain of TEP's debt agreements contain pricing based on our credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest we pay on our borrowings and the amount of fees we pay for LOCs and unused commitments.
Debt Covenants
Under certain agreements, should TEP fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of June 30, 2019,March 31, 2020, TEP was in compliance with these covenants.
We do not have any provisions in any of our debt or lease agreements that would cause an event of default or cause amounts to become due and payable in the event of a credit rating downgrade.
Contribution from Parent
TEP received equity contributions of $150 million from UNS Energy in the first three months of 2020 and received no equity contributions in the second quarter or first sixthree months of 20192019. On April 27, 2020, UNS Energy approved an equity contribution up to $100 million to TEP to be paid on or 2018.

before June 30, 2020.
Dividends Paid to Parent
TEP did not declare or pay dividends to UNS Energy in the second quarter or first sixthree months of 20192020 or 2018. On July 22, 2019, TEP declared a $38 million dividend to UNS Energy which was paid July 30, 2019.
Master Trading Agreements
TEP conducts its wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, TEP may be required to post credit enhancements in the form of cash or LOCs due to exposures exceeding unsecured credit limits provided to TEP based on changes inin: (i) contract values, changes in TEP’svalues; (ii) our credit ratings,ratings; or (iii) material changes in TEP’sour creditworthiness. As of June 30, 2019,March 31, 2020, TEP had posted no cash or LOCs as credit enhancements with its counterparties.counterparties related to our wholesale marketing or risk management activities. As of May 5, 2020, there was no collateral posted.

Capital Expenditures
TEP's routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. TEP is prioritizing capital projects to mitigate supply chain risk and other potential impacts of the COVID-19 pandemic and ensure we continue providing safe and reliable service while supporting public health. As a result, we expect to have reductions in forecasted capital expenditures due to prioritizing certain projects and postponing others. In the first sixthree months of 2019,2020, there have beenwere no material changes to capital expenditures as reported in our 2018 Annual Report on Form 10-K, except as noted below:
In March 2019 we entered into a build-transfer agreement to develop a 247 MW wind-power electric generation facility (Oso Grande), which established the anticipated timing and amount of capital expenditure payments for the Oso Grande project. The agreement contemplates capital expenditures of $259 million in 2019 and $111 million in 2020, compared to $43 million in 2019 and $309 million in 2020, which had been included with respect to this project in the forecasted capital expenditures for renewable energy generation facilities in our 2018 Annual Report on Form 10-K.
Contractual Obligations
In the first sixthree months of 2019,2020, there have beenwere no material changes outside the ordinary course of business to contractual obligations as reported in our 20182019 Annual Report on Form 10-K, except as noted below:
In March 2019, we entered into a build-transfer agreement to develop Oso Grande, which is expected to be completed by December 2020. The agreement increased our contractual obligations by $259 million in 2019 and $111 million in 2020, contingent upon certain performance obligations.10-K.
Off-Balance Sheet Arrangements
Other than the unrecorded contractual obligations reported on the contractual obligations table presented in our 20182019 Annual Report on Form 10-K, we do not have any arrangements or relationships with entities that are not consolidated into the financial statements.
Income Tax Position
Tax legislation previouslyTEP did not make any U.S. federal or Arizona State income tax payments in effect included provisions that made qualified property placed in service before 2018 eligible for bonus depreciation for tax purposes. In addition, the IRS issued guidance relatedfirst three months of 2020 due to the treatment of expenditures to maintain, replace, or improve property. These provisions were an acceleration of tax benefits we otherwise would have received over a longer period of time and createdexisting net operating loss and tax credit carryforwards that are used to offset future taxable income.As a result,in those jurisdictions. Based on our remaining tax carryforward balances, we did not pay any federal or state income taxes in the first six months of 2019. We offset net operating loss carryforwards against taxable income and do not expect to makeanticipate making federal or state income tax payments of a material nature for the next several years.
Under the TCJA, existing AMT credit carryforwards willcould be refunded if notor used to offset U.S. federal income tax liabilities.liabilities through our 2021 tax year. In response to the COVID-19 pandemic, the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was signed into law March 27, 2020. Along with other significant provisions, the CARES Act further accelerated the recovery of AMT credits by allowing corporations to immediately claim refunds of all unused carryforward balances. As a result, TEP received no refunds in the first six months of 2019 and expects to receive refunds of approximately $14 million in 2019, $7 millionAMT credit refunds in 2020, and $3 million in 2021 and 2022.2020.
See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information regarding the TCJA.
Payroll Tax
The CARES Act also allows employers to defer the deposit and payment of the employer's share of social security taxes. TEP is deferring the deposit of the employer's portion of social security tax through the end of 2020. We expect the deferred deposits to be approximately $7 million, and be paid to the IRS in equal payments in 2021 and 2022.
Environmental Matters
The EPAEnvironmental Protection Agency (EPA) regulates the amount of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), particulate matter, mercury and other by-products produced by generation facilities. We may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at our generation facilities. Environmental laws and regulations are subject to a range of interpretations, which may ultimately be resolved by the courts. Because these laws and regulations continue to evolve, we are unable to predict the impact they may have on our operations and consolidated

financial results. Complying with these changes may reduce operating efficiency and increase capital and operating costs. TEP will request recovery from its customers of the costs of environmental compliance through cost recovery mechanisms and Retail Rates. See Note 7 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on the Broadway-Pantano site.
Regional Haze Regulations
The Environmental Protection Agency's (EPA)EPA's Regional Haze rule requires emission reductions from certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rule calls for states to establish goals and emission reduction strategies for improving visibility in these areas. States must submit these goals and strategies to the EPA for approval in the form of a State Implementation Plan (SIP), and must review and submit revisions to the SIP on a periodic basis.
In December 2016, the EPA signed a final rule that, among other things, changed the submittal date for the next Regional Haze SIP revisions from 2018 to 2021. The Arizona Department of Environmental Quality (ADEQ)ADEQ began to develop a control strategy with a focus on making reasonable progress

toward the national visibility goal. In July 2019, the ADEQ notified TEP that Sundt Unit 3 and Springerville Units 1 and Sundt2 had been selected for potential emissions controls evaluation. The
TEP conducted the potential emissions controls evaluation, commonly referred to as the four factor analysis, for both facilities. These evaluations are to be performed for each facility andwere submitted to the ADEQ by December 2019.
in March 2020 for the agency's use in developing the revised SIP. TEP will continue to work with the agency to determine compliance strategies as needed, however, TEP cannot predict the outcome of these matters at this time.
The ADEQ to prepare andmust submit the evaluationsrevised SIP to the EPA for approval by the required deadline.July 2021. Based on current Regional Haze requirement time-frames, TEP anticipates that impacts,compliance strategies, if any, to the facilities will likely occurbe required to be implemented three to five years after the 2021 SIP submittal date. TEP cannot predict the ultimate outcome of these matters at this time.
Greenhouse Gas Regulation
In August 2015, the EPA issued the Clean Power Plan (CPP) limiting CO2CO2 emissions from existing and new fossil fuel-based generation facilities. The CPP establishedestablishes state-level CO2CO2 emission rates and mass-based goals that apply to fossil fuel-based generation. The plan targeted CO2targets CO2 emissions reductions for existing facilities by 2030 and establishes interim goals that begin in 2022.
In June 2019, the EPA repealed the CPP, and replaced it with the Affordable Clean Energy (ACE) rule, establishing new emissions guidelines. The new rule rebalances the roles between the states and the EPA. Under the new rule, the EPA would set emission guidelines based on the Best System of Emission Reduction (BSER) for Greenhouse Gas (GHG) emissions. The BSER for GHG emissions from existing coal-fired electric utility generating unitsgeneration facilities is defined as heat-rate (efficiency) improvementsHeat-Rate Improvements (HRI) that can be applied at the source. The states would then use these emission guidelines to establish state performance standards, considering source specific factors such as the remaining useful life of an individual unit.
StatesThe ADEQ began the stakeholder process in November 2019 and notified subject facilities that HRI analysis would be due to the agency by December 2020. We are in in the process of conducting the HRI analysis for Springerville Units 1 and 2, and therefore cannot predict the outcome of these matters at this time. However, we do not anticipate a material impact to Springerville Units 1 and 2 at this time.
Effective September 2019, states will have three years to submit plans to the EPA establishing performance standards. The EPA has 12 months to act on a complete state submittal. If a state plan is not approved, or a state fails to submit a plan within the allotted three years, the EPA would have two years to issue a federal plan.
TEP does not anticipate a material impact to its facilities at this time. TEP will continue to work with other Arizona utilities, as well as the appropriate regulatory agencies, to develop compliance strategies as needed.
TEP anticipates that there will be legalLegal challenges whichto the rule could delay the effectiveness and implementation of the new rule. On March 23, 2020, the U.S. Court of Appeals for the D.C. Circuit Court postponed the briefing schedule, pending further order of the court, in judicial challenges to the ACE rule in light of the COVID-19 pandemic.
Coal Combustion Residuals Regulation
In April 2015, the EPA issued a final rule requiring disposal of coal ash and other coal combustion residualsCoal Combustion Residuals (CCR) to be managed as a solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA) for disposal in landfills and/or surface impoundments. Due to the planned early retirement of Navajo, our share of costs to comply was less than $1 million as of June 30, 2019. We will continue to incur additional operating costs for on-going groundwater monitoring and eventual site closure. Our share of costs to comply at Four Corners is estimated to be $2$3 million, the majority of which is expected to be capital expenditures associated with site preparation and installation of the groundwater monitoring well system.
In December 2016, Congress approved the Water Infrastructure Improvements for the Nation (WIIN) Act, which authorizes the States to establish permit programs under RCRA for implementing regulation for CCR. In response to the WIIN Act and RCRA rulemaking petitions, the EPA has indicated that it intends to conduct two phases of CCR rule revisions. In July 2018, the EPA signed a Phase 1, Part 1 final rule which: (i) revised groundwater protection standards for rule-specific constituents without maximum containment levels; (ii) incorporated risk-based changes under an EPA-approved state permit program or an EPA permit program; and (iii) extended certain closure deadlines. In response to challenges to this rule, the EPA filed a motion to voluntarily remand the rule but not vacate it. On March 13, 2019, the U.S. Court of Appeals for the D.C. Circuit Court issued an order granting the EPA's motion, allowing the EPA nine months to undertake new rulemaking. In August 2019, the EPA issued the Phase 2 rule revision proposal. TEP does not anticipate a

material impact on operations or financial results from revisions to the Phase 1, Part 1 rule. The EPA anticipates finalizing the Phase 1, Part 2anticipated proposed rule in 2019. The second phase is also anticipated to be finalized in 2019.revisions.
On May 3, 2019, the ADEQ filed a Notice of Proposed Expedited Rulemaking to exempt federally regulated CCR disposal units from certain redundant provisions of Arizona’s Aquifer Protection Permit program. TEP is continuing to work with other affected utilities and the ADEQ to explore the possibility of developing a State administered program to enforce CCR regulation.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Management's Discussion and Analysis of Financial Condition and Results of Operations is based on our Condensed Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to apply accounting policies and make estimates, judgments, and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements and related notes. Management believes that there have been no significant changes during the sixthree months ended June 30, 2019,March 31, 2020, to the items that we disclosed as our critical accounting policies and estimates in Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 20182019 Annual Report on Form 10-K.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
For a discussion of new accounting pronouncements affecting TEP, see Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
TEP’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. We can enter into interest rate swaps and financing transactions to manage changes in interest rates. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms.
The COVID-19 pandemic has had a negative impact on the global economy and financial markets. There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our 20182019 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES
TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13a–15(e) and Rule 15d–15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the United States Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by TEP in the reports that it files or submits under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, TEP’s Chief Executive Officer and Chief Financial Officer concluded that TEP’s disclosure controls and procedures were effective as of June 30, 2019.
While TEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting, there has beenMarch 31, 2020. There was no change in TEP’s internal control over financial reporting during the quarter ended June 30, 2019,March 31, 2020, that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.


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

ITEM 1A. RISK FACTORS
The business and financial results of TEP are subject to numerous risks and uncertainties. As a result, the risks and uncertainties discussed in Part I, Item 1A. Risk Factors in our 20182019 Annual Report on Form 10-K should be carefully considered. There have been no material changes in the assessment of our risk factors from those set forth in our 20182019 Annual Report on Form 10-K.10-K, except as noted below:

The widespread outbreak of an illness or any other communicable disease, or any other public health crisis, including the COVID-19 pandemic, could adversely affect our business, results of operations and financial condition.

TEP could be negatively impacted by the widespread outbreak of an illness or any other communicable disease, or any other public health crisis that results in economic and trade disruptions, including the disruption of global supply chains. In March 2020, the World Health Organization declared COVID-19 a pandemic. The COVID-19 pandemic has negatively impacted the global, national, and our local economy, disrupted global supply chains, and created significant volatility and disruption of financial markets. The COVID-19 pandemic has resulted in closure of school and certain business facilities, travel restrictions, disruptions to supply chains, and disruptions to workplaces as employees and contractors cease to be available to perform critical work functions. The extent of the impact of the COVID-19 pandemic on TEP’s operational and financial performance, including the ability to execute business strategies and initiatives in the expected time frame, the ability to obtain external financing, and the timing of regulatory actions, will depend on future developments, including the duration and spread of the pandemic and related restrictions on travel and transports, all of which are uncertain and cannot be predicted at this time. An extended period of global supply chain and economic disruption could materially affect TEP’s business, results of operations, access to sources of liquidity, and financial condition.

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Table of Contents

ITEM 6. EXHIBITS
EXHIBIT INDEX
Exhibit No. Description
 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by David G. Hutchens
   
 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by Frank P. Marino
   
 Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)
   
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
   
101.SCH XBRL Taxonomy Extension Schema Document
   
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document
   
101.LAB XBRL Taxonomy Extension Label Linkbase Document
   
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document
   
101.DEF XBRL Taxonomy Extension Definition Linkbase Document
   
104 
The cover page from the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2019,
March 31, 2020, formatted in Inline XBRL and contained in Exhibit 101
*Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.



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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
   TUCSON ELECTRIC POWER COMPANY
   (Registrant)
    
Date:August 1, 2019May 5, 2020 /s/ Frank P. Marino
   Frank P. Marino
   Sr. Vice President and Chief Financial Officer
   (Principal Financial Officer)
    
    


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