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
xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2017March 31, 2024
OR
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
☐    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
Commission File Number 1-5924
TUCSON ELECTRIC POWER COMPANY
(Exact name of registrant as specified in its charter)
Arizona
(State or other jurisdiction of incorporation or organization)
86-0062700
(I.R.S. Employer Identification No.)

88 East Broadway Boulevard, Tucson, AZ 85701
(Address of principal executive offices)(Zip Code)
Registrant's telephone number, including area code: (520) 571-4000
(Former name, former address and former fiscal year, if changed since last report): N/A

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. Yesx ☒ No o☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x☒ No o☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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. (Check one):
Large Accelerated Filer o☐Accelerated Filer o☐Non-Accelerated Filer x☒Smaller Reporting Company o☐Emerging Growth Company o☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o☐ No x☒
All shares of outstanding common stock of Tucson Electric Power Company are held by its parent company, UNS Energy Corporation, which is an indirect, wholly-owned subsidiary of Fortis Inc. There were 32,139,434 shares of common stock, no par value, outstanding as of November 2, 2017.April 30, 2024.





Table of Contents
iii
viv
PART I
Condensed Consolidated Statements of Income
1
Condensed Consolidated Statements of Comprehensive Income
2
Condensed Consolidated Statements of Cash Flows
32
Condensed Consolidated Balance Sheets
43
Condensed Consolidated Statements of Changes in Stockholder's Equity
65
Notes to Condensed Consolidated Financial Statements
76
2318
Critical Accounting Policies and Estimates
3828
New Accounting PronouncementsStandards Issued and Not Yet Adopted
3828
3828
3828
PART II
PART II
4030
4030
Item 5. Other Information
40
4131
4232


ii





DEFINITIONS
DEFINITIONS
The abbreviations and acronyms used in the third quarter 2017this Form 10-Q are defined below:
INDUSTRY ACRONYMS AND CERTAIN DEFINITIONS
2023 IRPTEP's 2023 Integrated Resource Plan which outlines TEP's aspirational goal to reach net zero direct greenhouse gas emissions by 2050
2020 IRPTEP's 2020 Integrated Resource Plan which outlines TEP's plan to reduce its carbon emissions by 80% compared to 2005 by 2035
20172021 Credit AgreementThe 2021 Credit Agreement, as amended in June 2023, provides for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2026
2023 Rate OrderA rate orderOrder issued by the ACC resulting in a new rate structure for TEP, effective on February 27, 2017September 1, 2023
ACCArizona Corporation Commission
APS
ADEQArizona Public Service CompanyDepartment of Environmental Quality
ASU
AFUDCAccounting Standard UpdateAllowance for Funds Used During Construction
BART
CCRBest Available Retrofit TechnologyCoal Combustion Residuals
BBtuDGBillion British thermal unitsDistributed Generation
Cooling Degree DaysDSMAn index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures
DGDistributed Generation
DSMDemand Side Management
EE StandardsEDITEnergy Efficiency StandardsExcess Deferred Income Taxes
EPAEnvironmental Protection Agency
FERCEPCEngineering, Procurement, and Construction
FERCFederal Energy Regulatory Commission
FortisGAAPGenerally Accepted Accounting Principles in the United States of America
GHGGreenhouse Gas
IRAInflation Reduction Act, signed into law on August 16, 2022
LFCRLost Fixed Cost Recovery
LOCLetter(s) of Credit
OATTOpen Access Transmission Tariff
PPAPower Purchase Agreement
PPFACPurchased Power and Fuel Adjustment Clause
PTCProduction Tax Credit
RECRenewable Energy Credit
RESRenewable Energy Standard
Retail RatesRates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment
SIPState Implementation Plan
TCATransmission Cost Adjustor
ENTITIES AND GENERATING STATIONS
FortisFortis 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 CornersFour Corners Generating StationPower Plant
GAAP
Oso GrandeA 250 MW nominal capacity wind-powered electric generation facility, located in southeastern New Mexico
Roadrunner Reserve IGenerally Accepted Accounting PrinciplesA standalone battery energy storage system facility with a nominal capacity rating of 200 MW and storage capacity of 800 MWh, located in southeast Tucson, expected to be placed in service in the United Statessecond half of America2025
Gila RiverGila River Generating Station
GWhGigawatt-hour(s)
Heating Degree DaysAn index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65
kWhKilowatt-hour(s)
LFCRLost Fixed Cost Recovery
LOCLetter(s) of Credit
MWMegawatt(s)
MWhMegawatt-hour(s)
NavajoNavajo Generating Station
NBVNet Book Value
PDEQPima County Department of Environmental Quality
Phase 2Second phase of TEP's rate case proceedings originally filed November 2015
PNMPublic Service Company of New Mexico
PPAPower Purchase Agreement
PPFACPurchased Power and Fuel Adjustment Clause
Regional Haze RulesRules promulgated by the EPA to improve visibility at national parks and wilderness areas
RESRenewable Energy Standard
Retail RatesRates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment
RICEReciprocating Internal Combustion Engine
San JuanSan Juan Generating Station
SESSouthwest Energy Solutions, Inc.
SJCCSpringervilleSan Juan Coal Company
SpringervilleSpringerville Generating Station
SRPSalt River Project Agricultural Improvement and Power District
SundtH. Wilson Sundt Generating Station

iii



TEP
TEPTucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
Third-Party OwnersWilmington Trust Company and William J. Wade, as Owner Trustee and Co-trustee under a separate trust agreement with each of Alterna Springerville LLC (Alterna) and LDVF1 TEP LLC (LDVF1) (Alterna and LDVF1, together with the Owner Trustees and Co-trustees, the Third-Party Owners)
TSATransmission Service Agreement
UNS ElectricUNS Electric, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
UNS EnergyUNS Energy Corporation, the parent company of TEP, whose principal executive offices are located at 88 East Broadway Boulevard, Tucson, Arizona 85701
UNS Energy AffiliatesAffiliated subsidiaries of UNS Energy Corporation including UniSource Energy Services, Inc., UNS Electric, Inc.,and UNS Gas Inc., and Southwest Energy Solutions, Inc.
UNS GasUNS Gas, Inc., an indirect wholly-owned subsidiary of UNS Energy Corporation
VIEVariable Interest Entity

UNITS OF MEASURE
BBtuBillion British thermal unit(s)
GWhGigawatt-hour(s)
kWhKilowatt-hour(s)
MWMegawatt(s)
MWhMegawatt-hour(s)


iv
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Table of Contents

FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Tucson Electric Power Company (TEPTEP, or the Company)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 economical, 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, aspires, may, plans, predicts, potential, projects, would, strategy, 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 thesuch 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 20162023 Annual Report on Form 10-K; Part II, Item 1A. Risk Factors;Factors of this Form 10-Q; Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations;Operations of this Form 10-Q; and other parts of this report. These factors include: voter initiatives and state and federal regulatory and legislative decisions and actions;actions, including changes in tax, inclusive of the IRA and evolving interpretive guidance related thereto, and energy policies; any change in the structure of utility service in Arizona resulting from the ACC or state legislature's examination of the state's energy policies; changes in, and compliance with, environmental laws and regulationregulatory decisions and policies that could increase operating and capital costs, reduce generatinggeneration facility output, or accelerate generatinggeneration facility retirements; unfavorable rulings, penalties, or findings by the FERC; regional economic and market conditions whichthat could affect customer growth and energyelectricity usage; potential changes in energythe benefits of participation in the Energy Imbalance Market; changes in electricity consumption by retail customers; risks related to climate change, including shifts in weather variationsseasonality and extreme weather events, affecting energy usage;electricity usage of our customers, operational performance, and operating and capital costs to ensure system reliability; our forecasts of peak demand and whether existing generation capacity and PPAs are sufficient to meet the demand plus reserve margin requirements; the cost of debt and equity capital and access to capital markets and bank markets;markets, which may affect our ability to raise additional capital and to 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; our ability to manage timelines and budgets related to capital projects, including EPC agreements to develop standalone battery energy storage facilities, and/or to obtain the anticipated performance or other benefits of such capital projects; the potential inability to make additions to our existing high voltage transmission system; unexpected increases in operations and maintenance expense;expense, including increases due to inflationary effects, heightened geopolitical instability, and/or global supply chain challenges; resolution of pending litigation matters; changes in accounting standards; changes in our critical accounting policies and estimates; the ongoing impact of mandated energy efficiency and distributed generation (DG)DG initiatives; our ability to effectively implement plans to meet our goals related to reducing carbon emissions by 2035 and 2050, and the potential impact on our financial condition; changes to long-term contracts; the cost of fuel and power supplies; fluctuations or increases in commodity prices; the ability to obtain coal or natural gas from our suppliers; the timing and cost of generation facility decommissioning and mine reclamation activities; cyber-attacks, data breaches, or other challengescyberspace attacks to our information security includingand our operations and technology systems;infrastructure, including attacks that may rise from heightened geopolitical instability; physical attacks to our electric generation, transmission, and distribution assets; the performance of TEP's generating facilities.generation facilities, including renewable generation resources; the extent of the impact of a global health or other crisis on our business and operations, and any economic and/or societal disruptions resulting therefrom and from the government actions taken in response thereto; and the implementation of our 2023 IRP.



v
iv


Table of Contents

PART I
ITEM 1. FINANCIAL STATEMENTS
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(Amounts in thousands)
Three Months Ended March 31,
Three Months Ended March 31,
Three Months Ended March 31,
202420242023
Operating Revenues
Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Operating Revenues       
Retail$340,410
 $320,379
 $820,453
 $780,782
Wholesale43,868
 32,151
 130,242
 80,648
Other32,932
 41,605
 87,041
 93,668
Total Operating Revenues417,210
 394,135
 1,037,736
 955,098
Operating Expenses       
Operating Expenses
Operating Expenses
Fuel
Fuel
Fuel91,754
 86,530
 218,226
 217,444
Purchased Power38,903
 30,031
 107,039
 71,794
Transmission and Other PPFAC Recoverable Costs10,285
 7,143
 27,167
 17,633
Increase (Decrease) to Reflect PPFAC Recovery Treatment(9,166) 5,091
 (24,773) 19,356
Total Fuel and Purchased Power131,776
 128,795
 327,659
 326,227
Operations and Maintenance89,862
 88,699
 256,493
 260,278
Depreciation38,302
 36,565
 114,667
 108,110
Amortization5,463
 5,558
 16,323
 16,579
Taxes Other Than Income Taxes13,549
 12,646
 40,329
 38,376
Total Operating Expenses278,952
 272,263
 755,471
 749,570
Operating Income138,258
 121,872
 282,265
 205,528
Other Income (Deductions)       
Interest Income30
 11
 556
 78
Other Income1,738
 1,774
 12,630
 4,427
Other Expense(1,072) (1,166) (2,609) (2,052)
Appreciation in Value of Investments912
 722
 2,130
 1,582
Total Other Income (Deductions)1,608
 1,341
 12,707
 4,035
Operating Income
Operating Income
Other Income (Expense)
Other Income (Expense)
Other Income (Expense)
Interest Expense       
Long-Term Debt15,531
 15,545
 46,461
 46,522
Capital Leases613
 821
 1,941
 2,534
Other Interest Expense147
 114
 570
 372
Interest Capitalized(525) (436) (1,645) (1,297)
Total Interest Expense15,766
 16,044
 47,327
 48,131
Income Before Income Taxes124,100
 107,169
 247,645
 161,432
Interest Expense
Interest Expense
Allowance For Borrowed Funds
Allowance For Equity Funds
Unrealized Gains (Losses) on Investments
Other, Net
Total Other Income (Expense)
Income Before Income Tax Expense
Income Before Income Tax Expense
Income Before Income Tax Expense
Income Tax Expense42,100
 35,556
 83,951
 49,985
Net Income82,000
 71,613
 163,694
 111,447
The accompanying notes are an integral part of these financial statements.




1


TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME CASH FLOWS (Unaudited)
(Amounts in thousands)
 Three Months Ended September 30, Nine Months Ended September 30,
 2017 2016 2017 2016
Comprehensive Income       
Net Income$82,000
 $71,613
 $163,694
 $111,447
Other Comprehensive Income       
Net Changes in Fair Value of Cash Flow Hedges:       
Net of Income Tax Expense of $79 and $155121
 247
    
Net of Income Tax Expense of $212 and $242    336
 385
Supplemental Executive Retirement Plan Adjustments:       
Net of Income Tax Expense of $44 and $3469
 55
    
Net of Income Tax Expense of $130 and $104    209
 168
Total Other Comprehensive Income, Net of Tax190
 302
 545
 553
Total Comprehensive Income$82,190
 $71,915
 $164,239
 $112,000
Three Months Ended March 31,
20242023
Cash Flows from Operating Activities
Net Income$51,181 $46,893 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation Expense55,604 47,140 
Amortization Expense7,736 9,691 
Amortization of Debt Issuance Costs763 782 
Use of Renewable Energy Credits for Compliance11,984 11,402 
Deferred Income Taxes5,590 4,657 
Pension and Other Postretirement Benefits Expense4,510 3,794 
Pension and Other Postretirement Benefits Funding(953)(1,186)
Allowance for Equity Funds Used During Construction(5,252)(2,893)
Changes in Current Assets and Current Liabilities:
Accounts Receivable26,817 133,058 
Materials, Supplies, and Fuel Inventory(3,350)(10,040)
Regulatory Assets48,234 294 
Other Current Assets(1,930)(887)
Accounts Payable and Accrued Charges24,007 (104,341)
Income Taxes Receivable/Payable(688)(777)
Regulatory Liabilities(3,703)(2,818)
Other, Net(30,448)(13,858)
Net Cash Flows—Operating Activities190,102 120,911 
Cash Flows from Investing Activities
Capital Expenditures(133,283)(116,683)
Purchase Intangibles, Renewable Energy Credits(11,956)(12,961)
Contributions in Aid of Construction965 799 
Net Cash Flows—Investing Activities(144,274)(128,845)
Cash Flows from Financing Activities
Proceeds from Borrowings, Revolving Credit Facility15,000 — 
Repayments of Borrowings, Revolving Credit Facility(15,000)— 
Proceeds from Issuance, Long-Term Debt—Net of Discount
— 373,954 
Repayments of Long-Term Debt— (240,745)
Payment of Debt Issuance Costs— (3,738)
Contribution from Parent— 5,900 
Other, Net317 (560)
Net Cash Flows—Financing Activities317 134,811 
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash46,145 126,877 
Cash, Cash Equivalents, and Restricted Cash, Beginning of Period42,595 50,981 
Cash, Cash Equivalents, and Restricted Cash, End of Period$88,740 $177,858 
The accompanying notes are an integral part of these financial statements.


2



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in thousands)
 Nine Months Ended September 30,
 2017 2016
Cash Flows from Operating Activities   
Net Income$163,694
 $111,447
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:   
Depreciation Expense114,667
 108,110
Amortization Expense16,323
 16,579
Amortization of Debt Issuance Costs1,763
 2,176
Use of Renewable Energy Credits for Compliance17,434
 13,048
Deferred Income Taxes83,954
 49,972
Pension and Other Postretirement Benefits Expense12,029
 11,504
Pension and Other Postretirement Benefits Funding(12,763) (12,672)
Allowance for Equity Funds Used During Construction(4,145) (3,410)
FERC Transmission Refund Payable(4,878) 18,783
Changes in Current Assets and Current Liabilities:   
Accounts Receivable(59,016) (24,743)
Materials, Supplies, and Fuel Inventory452
 8,366
Regulatory Assets(2,407) (7,533)
Accounts Payable and Accrued Charges25,628
 23,139
Regulatory Liabilities(10,258) 21,648
Other, Net(5,213) 5,033
Net Cash Flows—Operating Activities337,264
 341,447
Cash Flows from Investing Activities   
Capital Expenditures(215,826) (187,678)
Purchase, Springerville Unit 1 Assets—
 (85,000)
Purchase Intangibles, Renewable Energy Credits(40,838) (31,192)
Contributions in Aid of Construction3,265
 1,965
Other, Net(975) —
Net Cash Flows—Investing Activities(254,374) (301,905)
Cash Flows from Financing Activities   
Proceeds from Borrowings, Revolving Credit Facilities35,000
 —
Repayments of Borrowings, Revolving Credit Facilities(35,000) —
Dividend Paid to Parent(35,000) (20,000)
Payments of Capital Lease Obligations(14,804) (14,080)
Other, Net641
 (4,107)
Net Cash Flows—Financing Activities(49,163) (38,187)
Net Increase in Cash and Cash Equivalents33,727
 1,355
Cash and Cash Equivalents, Beginning of Period35,962
 55,684
Cash and Cash Equivalents, End of Period$69,689
 $57,039
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)
September 30, 2017 December 31, 2016
March 31, 2024March 31, 2024December 31, 2023
ASSETS   
Utility Plant   
Utility Plant
Utility Plant
Plant in Service$5,633,029
 $5,975,139
Utility Plant Under Capital Leases167,413
 167,413
Plant in Service
Plant in Service
Construction Work in Progress
Construction Work in Progress
Construction Work in Progress165,139
 129,955
Total Utility Plant5,965,581
 6,272,507
Accumulated Depreciation and Amortization(2,153,176) (2,385,053)
Accumulated Amortization of Capital Lease Assets(109,743) (104,648)
Total Utility Plant, Net
Total Utility Plant, Net
Total Utility Plant, Net3,702,662
 3,782,806
   
Investments and Other Property47,099
 45,020
Investments and Other Property
Investments and Other Property
   
Current Assets   
Current Assets
Current Assets
Cash and Cash Equivalents69,689
 35,962
Accounts Receivable, Net186,007
 124,934
Cash and Cash Equivalents
Cash and Cash Equivalents
Accounts Receivable (Net of Allowance for Credit Losses of $11,263 and $11,676)
Fuel Inventory23,943
 25,887
Materials and Supplies103,435
 97,126
Regulatory Assets66,899
 56,340
Derivative Instruments4,912
 4,966
Other
Other
Other14,713
 13,793
Total Current Assets469,598
 359,008
Regulatory and Other Assets   
Regulatory Assets
Regulatory Assets
Regulatory Assets299,943
 225,453
Derivative Instruments549
 330
Other55,321
 37,372
Total Regulatory and Other Assets355,813
 263,155
Other Noncurrent Assets
Total Assets$4,575,172
 $4,449,989
Total Assets
Total Assets
The accompanying notes are an integral part of these financial statements.


(Continued)

3



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in thousands, except share data)
September 30, 2017 December 31, 2016
CAPITALIZATION AND OTHER LIABILITIES   
March 31, 2024March 31, 2024December 31, 2023
CAPITALIZATION AND LIABILITIES
Capitalization
Capitalization
Capitalization   
Common Stock Equity:   
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of September 30, 2017, and December 31, 2016)$1,296,539
 $1,296,539
Common Stock Equity:
Common Stock Equity:
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2024 and December 31, 2023)
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2024 and December 31, 2023)
Common Stock (No Par Value, 75,000,000 Shares Authorized, 32,139,434 Shares Outstanding as of March 31, 2024 and December 31, 2023)
Capital Stock Expense(6,357) (6,357)
Retained Earnings402,102
 273,408
Accumulated Other Comprehensive Loss(4,010) (4,555)
Total Common Stock Equity1,688,274
 1,559,035
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of September 30, 2017, and December 31, 2016)—
 —
Capital Lease Obligations28,518
 39,267
Preferred Stock (No Par Value, 1,000,000 Shares Authorized, None Outstanding as of March 31, 2024 and December 31, 2023)
Long-Term Debt, Net
Long-Term Debt, Net
Long-Term Debt, Net1,454,085
 1,453,072
Total Capitalization3,170,877
 3,051,374
Current Liabilities   
Capital Lease Obligations47,224
 51,765
Current Maturities of Long-Term Debt, Net
Current Maturities of Long-Term Debt, Net
Current Maturities of Long-Term Debt, Net
Accounts Payable
Accounts Payable
Accounts Payable95,353
 89,797
Accrued Taxes Other than Income Taxes60,167
 37,639
Accrued Employee Expenses25,034
 29,465
Accrued Interest13,135
 14,508
Regulatory Liabilities66,066
 76,069
Customer Deposits24,676
 25,778
Derivative Instruments4,579
 2,641
Other10,830
 17,837
Total Current Liabilities347,064
 345,499
Regulatory and Other Liabilities   
Deferred Income Taxes, Net
Deferred Income Taxes, Net
Deferred Income Taxes, Net619,838
 529,148
Regulatory Liabilities205,546
 300,700
Pension and Other Postretirement Benefits125,762
 131,630
Derivative Instruments5,041
 2,629
Other101,044
 89,009
Total Regulatory and Other Liabilities1,057,231
 1,053,116
Other Noncurrent Liabilities
Total Liabilities
   
Commitments and Contingencies
 
Commitments and Contingencies
Commitments and Contingencies
   
Total Capitalization and Other Liabilities$4,575,172
 $4,449,989
Total Capitalization and Liabilities
Total Capitalization and Liabilities
Total Capitalization and Liabilities
The accompanying notes are an integral part of these financial statements.


(Concluded)


4



TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY (Unaudited)
(Amounts in thousands)
 Common Stock Capital Stock Expense Retained Earnings Accumulated Other Comprehensive Loss Total Stockholder's Equity
Balances as of December 31, 2015$1,296,539
 $(6,357) $189,317
 $(4,564) $1,474,935
Net Income    111,447
   111,447
Other Comprehensive Income, Net of Tax      553
 553
Dividend Declared to Parent    (20,000)   (20,000)
Adoption of ASU, Cumulative Effect Adjustment    9,653
   9,653
Balances as of September 30, 2016$1,296,539
 $(6,357) $290,417
 $(4,011) $1,576,588
Common StockCapital Stock ExpenseRetained EarningsAccumulated Other Comprehensive LossTotal Stockholder's Equity
Balances as of December 31, 2022$1,696,539 $(6,357)$968,367 $(2,884)$2,655,665 
Net Income46,893 46,893 
Other Comprehensive Income (Loss), Net of Tax28 28 
Contribution from Parent5,900 5,900 
Balances as of March 31, 2023$1,702,439 $(6,357)$1,015,260 $(2,856)$2,708,486 
 Common Stock Capital Stock Expense Retained Earnings Accumulated Other Comprehensive Loss Total Stockholder's Equity
Balances as of December 31, 2016$1,296,539
 $(6,357) $273,408
 $(4,555) $1,559,035
Net Income    163,694
   163,694
Other Comprehensive Income, Net of Tax      545
 545
Dividend Declared to Parent    (35,000)   (35,000)
Balances as of September 30, 2017$1,296,539
 $(6,357) $402,102
 $(4,010) $1,688,274
Balances as of December 31, 2023$1,696,539 $(6,357)$1,162,921 $(3,829)$2,849,274 
Net Income51,181 51,181 
Other Comprehensive Income (Loss), Net of Tax46 46 
Balances as of March 31, 2024$1,696,539 $(6,357)$1,214,102 $(3,783)$2,900,501 
The accompanying notes are an integral part of these financial statements.

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NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION
TEP is a regulated utility that generates, transmits, and distributes electricity to approximately 422,000450,000 retail customers in a 1,155 square mile area in southeastern Arizona. TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. TEP is a wholly-owned subsidiary of UNS Energy, Corporation (UNS Energy), a utility services holding company. UNS Energy is an indirect wholly-owned subsidiary of Fortis Inc. (Fortis).Fortis.
BASIS OF PRESENTATION
TEP's condensed consolidated financial statementsCondensed Consolidated Financial Statements and disclosures are presented in accordance with Generally Accepted Accounting Principles (GAAP) in the United States of America,GAAP, including specific accounting guidance for regulated operations and the United States Securities and Exchange Commission's (SEC) interim reporting requirements.
The condensed consolidated financial statementsCondensed Consolidated Financial Statements include the accounts of TEP and its subsidiaries. In the consolidation process, accounts of the parentTEP and its subsidiaries are combined, and intercompany balances and transactions are eliminated. TEP jointly owns several generation facilities and transmission facilitiessystems with both affiliated and non-affiliated entities. TEP'sTEP records its proportionate share of jointly ownedof: (i) jointly-owned facilities is recorded in Utility Plant on the Condensed Consolidated Balance Sheets,Sheets; and its proportionate share of Operating Expenses(ii) operating costs associated with these facilities is included in the Condensed Consolidated Statements of Income. These condensed consolidated financial statementsCondensed 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 statementsConsolidated Financial Statements and footnotes in TEP's 20162023 Annual Report on Form 10-K.
The condensed consolidated financial statementsCondensed Consolidated Financial Statements are unaudited, but, in management's opinion, include all normal, recurring adjustments necessary for a fair presentationstatement 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. These reclassifications had no impact on TEP’s results of operation, financial position, or cash flows.
Variable Interest Entities
A Variable Interest Entity (VIE) is an entity in which equity investors lack the characteristics of a controlling financial interest or do not have sufficient equity investment at risk for the entity to finance its activities without additional subordinated financial support. TEP regularly reviews contracts to determine if it has a variable interest in an entity, if that entity is a Variable Interest Entity (VIE),VIE, and if itTEP is the primary beneficiary of the VIE. The primary beneficiary is required to consolidate the VIE when the variable interest holderit 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 Power Purchase Agreements (PPA)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 athe primary beneficiary of the VIEs on a quarterly basis.
As of September 30, 2017,March 31, 2024, the carrying amountamounts of assets and liabilities in the balance sheet that relatesrelate to variable interests under long-term renewable PPAs isare predominantly related to working capital accounts and generally representsrepresent the amounts owed by TEP for the deliveries associated with the current billing cycle. TEP's maximum exposure to loss is limited to the cost of replacing the power if the providers do not meet the production guarantee. However, the exposure to loss is mitigated as the Company would likely recover these costs through retail customer cost recovery mechanisms. See Note 2 for additional information related to cost recovery mechanisms.
RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
6
Effective January 1, 2016, TEP adopted accounting guidance that simplifies the accounting for share-based payment accounting. The guidance requires that excess tax benefits and tax deficiencies be recorded as an income tax benefit or expense on the income statement and eliminates the requirement that excess tax benefits be realized before companies can recognize them. On adoption, using the modified retrospective method of transition, TEP recorded a cumulative effect adjustment of $10 million to increase retained earnings and decrease deferred income taxes related to prior period unrecognized excess tax benefits. The impact on the income and the cash flow statements was not significant. TEP elected to recognize forfeitures when they occur.
Effective January 1, 2017, TEP adopted accounting guidance that requires the Company to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less

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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 in the balance sheet and reconciles their sum to Cash, Cash Equivalents, and Restricted Cash, End of Period on the Condensed Consolidated Statements of Cash Flows:
Three Months Ended March 31,
(in millions)20242023
Cash and Cash Equivalents$57 $144 
Restricted Cash included in:
Investments and Other Property22 21
Current Assets—Other10 13
Cash, Cash Equivalents, and Restricted Cash, End of Period$89 $178 
reasonably predictableRestricted cash primarily represents cash contractually required to be set aside to pay TEP's share of mine reclamation and decommissioning costs at San Juan.
Income Tax Expense
TEP realized PTC benefits associated with Oso Grande of completion, disposal,$4 million in Income Tax Expense on the Condensed Consolidated Statements of Income for the three months ended March 31, 2024 and transportation. 2023, respectively.
NEW ACCOUNTING STANDARDS ISSUED AND NOT YET ADOPTED
The following new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB) and the SEC has not yet been adopted and is not reflected in TEP’s financial statements. TEP is assessing the impact such guidance may have on TEP’s financial position, results of operations, cash flows, and disclosures.
Income Tax Disclosures
In December 2023, the FASB issued accounting guidance that requires disaggregated information about a reporting entity's effective tax rate reconciliation as well as information on income taxes paid. The amendments are effective for annual periods beginning January 1, 2025. The guidance should be applied on a prospective basis with the option to apply the standard retrospectively. Early adoption is permitted.
Reportable Segment Disclosures
In November 2023, the FASB issued accounting guidance that requires disclosure of this change in accounting principle did not have any impactsignificant segment expenses and new disclosures for entities with a single reportable segment. The amendments are effective for annual periods beginning on TEP as the Company recovers the cost of inventory through its rates.January 1, 2024 and interim periods beginning on January 1, 2025 and are to be applied retrospectively. Early adoption is permitted.
UTILITY PLANT
Utility Plant includes the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. Utility plant is reported at original cost. Original cost includes materials and labor, contractor services, construction overhead (when applicable), and an Allowance for Funds Used During Construction, less contributions in aid of construction.
RetirementsClimate-Related Disclosures
In March 2017,2024, the SEC issued a final rule that requires disclosure of: (i) financial statement impacts of severe weather events and other natural conditions; (ii) a roll forward of carbon offset and REC balances if material to the Company's plan to achieve climate-related targets or goals; and (iii) material impacts on estimates and assumptions in the financial statements. The rule is effective for TEP recordedfor annual periods beginning January 1, 2027 and is to be applied prospectively. In April 2024, the early retirementSEC issued an order staying the final rule pending judicial review of Unit 2 ofconsolidated challenges to the San Juan Generating Station (San Juan) and the coal handling facilities at H. Wilson Sundt Generating Station (Sundt) in accordance with provisions in a rate order issuedrules by the Arizona Corporation Commission (ACC) that took effect February 27, 2017 (2017 Rate Order). The Condensed Consolidated Balance Sheets reflect a: (i) $224 million decreaseCourt of Appeals for the Eighth Circuit. TEP cannot predict what, if any, changes in Plant in Service and Accumulated Depreciation and Amortization related to San Juan Unit 2; and (ii) $14 million decrease in Regulatory Assets and Accumulated Depreciation and Amortization related to the coal handling facilities at Sundt. See Note 2 for additional information related to the 2017 Rate Order.
In June 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo Generating Station (Navajo) to continue operations through December 2019 and begin decommissioning activities thereafter. TEP is currently recovering Navajo's capital and operating costs in base rates using a useful life of 2030. Asscope or timing may occur as a result of the planned early retirement of Navajo, $52 million ofpending litigation. TEP continues its assessment to prepare for the facility's net book value (NBV) and other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets as of September 30, 2017. See Note 2 for additional information related to the planned early retirement of Navajo.new rule.
In August 2017, TEP submitted an Air Quality Permit Application (Application) to the Pima County Department of Environmental Quality (PDEQ) related to a generation modernization project at Sundt that will add generation capacity in the form of reciprocating internal combustion engines (RICE) in 2019 and 2020. As part of the Application, TEP plans to early retire Sundt Units 1 and 2 by the end of 2020. TEP is currently recovering capital and operating costs for Sundt Units 1 and 2 in base rates using useful lives of 2028 and 2030, respectively. As a result of the planned early retirement, $32 million of the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets. See Note 2 for additional information related to the planned early retirement of Sundt Units 1 and 2.
Depreciation
Depreciation is recorded for owned utility plant on a group method straight-line basis at depreciation rates based on the economic lives of the assets. The ACC approves depreciation rates for all generation and distribution assets. Transmission assets are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). In the 2017 Rate Order, the ACC approved the results of a new depreciation study for TEP. In May 2017, TEP transferred $87 million from Regulatory Liabilities to Accumulated Depreciation and Amortization on the Condensed Consolidated Balance Sheets to reflect the impact of the revised depreciation study on the estimated cost of removal. See Note 2 for additional information related to the net cost of removal balance in Regulatory Liabilities.

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 facilities and transmission facilities,systems, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect the Company's business decisions and accounting practices.decisions. The FERC regulates termsrates and prices ofservices for electric transmission services and wholesale electricity sales.
2017 RATE ORDER
In February 2017, the ACC issued a rate order for new rates that took effect February 27, 2017. Provisions of the 2017 Rate Order include, but are not limited to:
a non-fuel base rate increase of $81.5 million, which includes $15 million of operating costs related to the 50.5% undivided interestpower sales in Unit 1 of Springerville Generating Station (Springerville) purchased by TEP in September 2016;

interstate commerce.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



a 7.04% return on original cost rate base, which includes a cost of equity component of 9.75% and a cost of debt component of 4.32%;
adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and
approval of a request to apply excess depreciation reserves against the unrecovered NBV of San Juan Unit 2 and the coal handling facilities at Sundt due to early retirement.
The ACC deferred matters related to net metering and rate design for new distributed generation (DG) customers to a second phase of TEP’s rate case (Phase 2), which is currently expected to be completed in the first quarter of 2018. TEP cannot predict the outcome of these proceedings.
COST RECOVERY MECHANISMS
TEP has received regulatory decisions that allow for more timely recovery of certain costs through recovery mechanisms. The difference between costs recovered through rates and actual approved costs is deferred. TEP defers over-recovered costs as a regulatory liability to return to customers and defers under-recovered costs as a regulatory asset to recover from customers in the future. Cost recovery mechanisms that have a material impact on TEP's operations or financial results are described below.
Purchased Power and Fuel Adjustment Clause
TEP's Purchased Power and Fuel Adjustment Clause (PPFAC)PPFAC rate is 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 rates designed to allow a regulated utility recovery of its costs of providing services and an opportunity to earn a reasonable return on its investment (Retail Rates);Retail Rates; and (ii) a true-up component that reconciles the differenceallows for reconciliation of differences between actual costs and those recovered in the preceding 12-month period. The PPFAC bank balance was over-collected by $20 million as of September 30, 2017 and by $38 million as of December 31, 2016.
period. In February 2017,May 2023, the ACC approved a rate adjustment designed to collect the then under-recovered PPFAC credit to begin returning the over-collected balance to customers. over 12 months.
The table below presentssummarizes the PPFAC regulatory asset (liability) balance:
Three Months Ended March 31,
(in millions)20242023
Beginning of Period$55 $124 
Deferred Fuel and Purchased Power Costs (1)
49 58 
PPFAC and Base Power Recoveries(97)(64)
End of Period$7 $118 
(1)Includes costs eligible for recovery through the PPFAC and base power rates.
Transmission Cost Adjustor
The TCA allows for timely recovery of actual costs required to provide transmission services to retail customers. The TCA is limited to the recovery, or refund, of costs associated with future changes in TEP's PPFACOATT rate. TEP files new TCA rates approved bywith the ACC:
PeriodCents per kWh
March 2017 through March 2018(0.20)
May 2016 through February 20170.15
April 2015 through April 20160.68
ACC in December each year based on changes in the OATT formula rate. New TCA rates take effect in January of each year.
Renewable Energy Standard
The ACC’s Renewable Energy Standard (RES)RES requires Arizona regulated utilities to increase their use of renewable energy each year until it represents at least 15% of their total annual retail energy requirementssales by 2025, with DG accounting for 30% of the annual energy requirement. The renewable energy requirement.requirement in 2024 is 14% of retail electric sales. Consistent with prior years, TEP plans to meet these requirements through a combination of utility-owned resources, PPAs, and customer-sited DG. Arizona utilities mustare required to file an annual RES implementation plan for review and approval by the ACC. TEP recovers approved costs of carrying out this plan from retail customers through a RES tariff.
In March 2017,2021, the ACC approved TEP's 20172021 RES implementation plan for the years 2021 and 2022 with a budget of $54 million, which was partially offset by applying $2 million of previously recovered carryover funds. TEP will recover the remaining $52 million through the RES surcharge.$66 million. The recovery funds the following:approved amount funds: (i) the above market cost of renewable power purchases; (ii) previously awarded performance-based incentives for customer installedcustomer-installed DG; and (iii) various other program costs. TEP suspended its rooftop solar program effective December 2016, but requested approval of a community solar program. The ACC is expected to consider this program in Phase 2 of TEP's rate case.
The percentage of retail kilowatt-hour (kWh) sales attributable to the RES in 2016 was 11%, which exceeded the overall 2016 RES requirement of 6%. Compliance is determined through the ACC's review of TEP's annual RES implementation plan. As TEP no longer pays incentives to obtain DG renewable energy credits, which are used to demonstrate compliance with the DG requirement,In June 2023, the ACC approved a waiverTEP's extension of the 2016 and 2017 residential DG requirement.2021 RES implementation plan through 2024.
In March 2024, TEP filed a proposal with the ACC to increase the RES tariff to account for under-collected RES funds totaling approximately $17 million as of December 31, 2023.
Energy Efficiency Standards
TEP is required to implement cost-effective Demand Side Management (DSM)DSM programs to comply with the ACC'sACC’s Energy Efficiency Standards (EE Standards). The EE Standards provide regulated utilities a DSM surcharge to recover the costs to implement DSM programs from retail customers the costs of implementing DSM programs, as well as an annual performance incentive. TEP records its annual DSM

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performance incentive for the prior calendar year in the first quarter of each year, with $2 million recorded in both 2017 and 2016. This performance incentive is included in Retail Revenues on the Condensed Consolidated Statements of Income.year.
In February 2016,the 2023 Rate Order, the ACC approved TEP’s 2016a 2023 energy efficiency implementation plan with a cumulative three-year budget of approximately $22$72 million, which was partially offset by applying $8 million of previously recovered carryover funds. TEP has been approved to collect the remaining $14 million from retail customersis collected through the DSM surcharge. In January 2024, TEP filed a proposal with the ACC to refund over-collected, uncommitted DSM surcharge funds totaling $10 million over a period not to exceed one year beginning in the first half of 2024.
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2020 IRP Energy savings realized through the programs will count toward meeting the EE Standards and the associated lost revenue will be partially recovered through the Lost Fixed Cost Recovery (LFCR) mechanism.Efficiency Target
In June 2016, TEP notified2022, as part of its acknowledgment of TEP's 2020 IRP, the ACC that it would not file a 2017set an annual 1.3% energy efficiency implementationtarget measured by retail MWh savings in each of the years 2023 through 2025. TEP will report its savings for these years in its first integrated resource plan following 2025 and instead continue the 2016 level of recovery through the end of 2017. TEP plans to reduce its costs and incentive levels for certain programs in order to minimize any potential under-collected DSM balance at the end of 2017. TEP filed its 2018TEP's periodic energy efficiency implementation plan in August 2017 and requested the Commission issue an order prior to the end of 2017.filings.
Lost Fixed Cost Recovery Mechanism
The LFCR mechanism provides for recovery of certain non-fuel costs that would go unrecovered between rate cases due to reduced retail kWh sales as a result of implementing ACC-approved energy efficiency programs and customer installedcustomer-installed DG. The LFCR mechanism is adjusted ineach rate case when the ACC approves new base rates. TEP records a regulatory asset and recognizes LFCR revenues when the amounts are verifiable regardlessbased on an estimate of when the lost retail kWh sales occur.during the period. TEP is required to make an annual filing with the ACC requesting recovery of the LFCR revenues recognized in the prior year. The recovery is subject to a year-over-year increase cap of 2% of TEP's applicable retail revenues, as approved in the 2017 Rate Order.revenues.
TEP recorded regulatoryREGULATORY ASSETS AND LIABILITIES
Regulatory assets and recognized LFCR revenues of $6 million and $17 million in the three and nine months ended September 30, 2017, respectively, and $5 million and $14 million in the three and nine months ended September 30, 2016, respectively. LFCR revenues are included in Retail Revenuesliabilities recorded on the Condensed Consolidated StatementsBalance Sheets are summarized in the table below:
($ in millions)Remaining Recovery Period
(years)		March 31, 2024December 31, 2023
Regulatory Assets
Pension and Other Postretirement Benefits (Note 7)Various$106 $107 
Early Generation Retirement CostsVarious47 48 
Derivatives (Note 8)640 26 
Lost Fixed Cost Recovery133 35 
Property Tax Deferrals (1)
130 30 
Final Mine Reclamation and Retiree Healthcare Costs (2)
1621 6 
Under-Recovered Purchased Energy Costs17 55 
Income Taxes Recoverable through Future Rates (3)
Various6 6 
Unamortized Loss on Reacquired DebtVarious5 5 
Other Regulatory AssetsVarious14 12 
Total Regulatory Assets309 330 
Less Current Portion1113 147 
Total Noncurrent Regulatory Assets$196 $183 
Regulatory Liabilities
Income Taxes Payable through Future Rates (3)
Various$225 $229 
Net Cost of Removal (4)
Various132 130 
Renewable Energy StandardVarious76 77 
Derivatives (Note 8)628 28 
Demand Side Management110 9 
Deferred Investment Tax CreditsVarious6 6 
Pension and Other Postretirement Benefits (Note 7)Various4 4 
Transmission Revenue Requirement Balancing Account12 5 
Other Regulatory LiabilitiesVarious— 1 
Total Regulatory Liabilities483 489 
Less Current Portion192 93 
Total Noncurrent Regulatory Liabilities$391 $396 
(1)Recorded as a regulatory asset based on historical ratemaking treatment allowing regulated utilities recovery of Income.

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.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



REGULATORY ASSETS AND LIABILITIES
Regulatory assets(2)Represents costs associated with TEP’s jointly-owned facilities at San Juan and liabilities recordedFour 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. Final mine reclamation costs are expected to be funded by TEP through 2040. San Juan Unit 1 was retired in 2022. In March 2024, the San Juan reclamation oversight committee approved a new final mine reclamation study which resulted in a $15 million increase in the balance sheetfinal mine reclamation regulatory asset.
(3)Amortized over five years, 10 years, or the lives of the assets.
(4)Represents an estimate of the future cost of retirement, net of salvage value. These are summarized in the table below:
(dollars in millions)
Remaining Recovery Period
(years)
 September 30, 2017 December 31, 2016
Regulatory Assets     
Pension and Other Postretirement Benefits (Note 7)Various $123
 $128
Early Generation Retirement Costs (1)
Various 83
 —
Final Mine Reclamation and Retiree Health Care Costs (2)
20 34
 27
Income Taxes Recoverable through Future RatesVarious 31
 29
Lost Fixed Cost Recovery1 29
 23
Property Tax Deferrals1 24
 23
Springerville Unit 1 Leasehold Improvements (3)
6 14
 17
Sundt Coal Handling Facilities (4)
N/A —
 14
Other Regulatory AssetsVarious 29
 20
Total Regulatory Assets  367
 281
Less Current Portion1 67
 56
Total Non-Current Regulatory Assets  $300
 $225
amounts collected through revenue for transmission, distribution, generation, and general and intangible plant which are not yet expended.
Regulatory Liabilities     
Net Cost of Removal (5)
Various $180
 $270
Renewable Energy StandardVarious 43
 32
Purchased Power and Fuel Adjustment Clause1 20
 38
Deferred Investment Tax CreditsVarious 20
 23
Other Regulatory LiabilitiesVarious 9
 14
Total Regulatory Liabilities  272
 377
Less Current Portion1 66
 76
Total Non-Current Regulatory Liabilities  $206
 $301
(1)
Includes the NBV 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 retirement of the facilities. As of September 30, 2017, Navajo and Sundt Units 1 and 2 are being fully recovered in base rates using various useful lives through 2030. See Note 1 for additional information related to the planned early retirement of Navajo and Sundt Units 1 and 2.
(2)
Includes costs associated with TEP’s jointly-owned facilities at San Juan, Four Corners Generating Station (Four Corners), and Navajo. TEP recognizes these costs at future value and is permitted to fully recover these costs through the PPFAC mechanism. The majority of final mine reclamation costs are expected to occur through 2037.
(3)
Represents investments TEP made to ensure that the facilities continued to provide safe, reliable service to TEP's customers. TEP received ACC authorization to recover leasehold improvement costs at Springerville Unit 1 over a 10-year amortization period.
(4)
The ACC authorized TEP to apply excess depreciation reserves against the unrecovered NBV in the 2017 Rate Order.
(5)
Net Cost of Removal represents an estimate of the future cost of retirement net of salvage value. These are amounts collected through revenue for transmission, distribution, generation plant, and general and intangible plant which are not yet expended. As a result of the 2017 Rate Order, $87 million was transferred from Net Cost of Removal to Accumulated Depreciation and Amortization to reflect the impact of the revised depreciation study on the estimated cost of removal.
Regulatory assets are either being collected or are expected to be collected through Retail Rates. With the exception of Early Generation Retirement Costs, Income Taxes Recoverable through Future Rates, and Springerville Unit 1 Leasehold Improvements,Under-Recovered Fuel and Purchased Energy Costs, 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, TEP does not paypays a return on the majority of its regulatory liabilities.liability balances.


11NOTE 3. REVENUE
DISAGGREGATION OF REVENUES
TableTEP earns most of Contentsits 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 March 31,
(in millions)20242023
Retail$282 $233 
Wholesale89 126 
Other Services39 31 
Revenues from Contracts with Customers410 390 
Alternative Revenues9 13 
Other34 33 
Total Operating Revenues$453 $436 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



FERC COMPLIANCE
In 2016, the FERC issued orders relating to certain late-filed transmission service agreements (TSAs), which resulted in TEP recording a liability and paying time-value refunds to the counterparties of these TSAs. In May 2017, the FERC informed TEP that the related investigation was closed. See Note 6 for additional information related to FERC compliance associated with these transmission contracts.

NOTE 3.4. ACCOUNTS RECEIVABLE
The following table presents the components of Accounts Receivable Net on the Condensed Consolidated Balance Sheets:
(in millions)March 31, 2024December 31, 2023
Retail$89 $109 
Retail, Unbilled47 57 
Retail, Allowance for Credit Losses(11)(12)
Wholesale (1)
29 37 
Due from Affiliates (Note 5)13 7 
Other26 19 
Accounts Receivable$193 $217 
(1)Includes $5 million as of March 31, 2024, and $10 million as of December 31, 2023, of receivables related to revenue from derivative instruments.
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(in millions)September 30, 2017 December 31, 2016
Customer$118
 $74
Due from Affiliates (Note 4)7
 9
Unbilled49
 34
Other18
 13
Allowance for Doubtful Accounts(6) (5)
Accounts Receivable, Net$186
 $125
ALLOWANCE FOR CREDIT LOSSES

TEP separately evaluates retail, wholesale, and other accounts receivable for credit losses and has not recorded an allowance for credit losses for non-retail accounts receivable. The allowance is estimated based on historical collection patterns, sales, current conditions, and reasonable and supportable forecasts. 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 March 31,
(in millions)20242023
Beginning of Period$(12)$(9)
Credit Loss Expense(1)(1)
Write-offs2 2 
End of Period$(11)$(8)

NOTE 4.5. RELATED PARTY TRANSACTIONS
TEP engages in various transactions with Fortis, UNS Energy, and its affiliated subsidiaries including UNS Electric, Inc. (UNS Electric), UNS Gas, Inc. (UNS Gas), and Southwest Energy Solutions, Inc. (SES) (collectively, UNS Energy Affiliates).Affiliates. These transactions includeinclude: (i) the sale and purchase of power and transmission services,services; (ii) common cost allocations,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)March 31, 2024December 31, 2023
Receivables from Related Parties
UNS Energy$6 $— 
UNS Electric5 5 
UNS Gas2 2 
Total Due from Related Parties$13 $7 
Payables to Related Parties
UNS Energy$5 $1 
UNS Electric1 1 
UNS Gas— 1 
Total Due to Related Parties$6 $3 
(in millions)September 30, 2017 December 31, 2016
Receivables from Related Parties   
UNS Electric$5
 $7
UNS Gas2
 2
Total Due from Related Parties$7
 $9
    
Payables to Related Parties   
SES$2
 $2
UNS Electric1
 —
Total Due to Related Parties$3
 $2

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The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income:
Three Months Ended March 31,
(in millions)20242023
Goods and Services Provided by TEP to Affiliates
Common Costs, UNS Energy Affiliates (1)
$6 $6 
Transmission Revenues, UNS Electric (2)
2 2 
Wholesale Revenues, UNS Electric (2)
2 7 
Goods and Services Provided by Affiliates to TEP
Corporate Services, UNS Energy (3)
$3 $3 
Capacity Charges, UNS Gas (4)
1 1 
Purchased Power, UNS Electric (2)
— 1 
 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2017 2016 2017 2016
Goods and Services Provided by TEP to Affiliates
 
    
Transmission Revenues, UNS Electric (1)
$2
 $2
 $5
 $5
Control Area Services, UNS Electric (2)
1
 1
 2
 2
Common Costs, UNS Energy Affiliates (3)
4
 3
 12
 10
        
Goods and Services Provided by Affiliates to TEP       
Supplemental Workforce, SES (4)
4
 3
 11
 10
Corporate Services, UNS Energy (5)
1
 1
 4
 5
Corporate Services, UNS Energy Affiliates (6)
1
 1
 3
 3
(1)
TEP and UNS Electric sell power and transmission services to each other. Wholesale power is sold at prevailing market prices while transmission services are sold at FERC-approved rates through the applicable Open Access Transmission Tariff.
(2)
TEP charges UNS Electric for Control Area Services under a FERC-approved Control Area Services Agreement.
(3)
Common Costs(1)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 are deemed reasonable by management.
(5)
Costs for Corporate Services at UNS Energy are allocated to its subsidiaries using the Massachusetts Formula, an industry accepted method of allocating common costs to affiliated entities. TEP's allocation is approximately 82% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis management fees. TEP's share of Fortis' management fees were $1 million and $3 million for the three and nine months ended September 30, 2017, respectively, and $1 million and $4 million for the three and nine months ended September 30, 2016, respectively.
(6)
Costs for Corporate Services (e.g., finance, accounting, tax, legal, and information technology) and other labor services for UNS Energy Affiliates are directly assigned to the benefiting entity at a fully burdened cost when possible.
DIVIDENDS PAID TO PARENT
TEP declared and paid a $35 million dividend to UNS Energy in the three and nine months ended September 30, 2017, and a $20 million dividend to UNS Energy in the three and nine months ended September 30, 2016.

NOTE 5. DEBT, CREDIT FACILITY, AND CAPITAL LEASE OBLIGATIONS
There have been no significant changes to TEP's debt, credit facility, or capital lease obligations from those reported in its 2016 Annual Report on Form 10-K, except as noted below.
CREDIT FACILITY
TEP's revolving credit facility provides for $250 million of revolving credit commitments with a Letter of Credit (LOC) sublimit of $50 million through its original October 2020 maturity. As permitted by the credit facility, in October 2017 TEP requested and was grantedACC as part of the secondof its two one-year extensions effectively extending the final maturity date to October 2022.
COVENANT COMPLIANCE
As of September 30, 2017, TEP was in compliance with the terms of its credit and long-term debt agreements.


rate case process.
13
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(2)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 OATT.


(3)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 85% of UNS Energy's allocated costs. Corporate Services, UNS Energy includes legal, audit, and Fortis' management fees. TEP's share of Fortis' management fees was $2 million in each of the three months ended March 31, 2024 and 2023.
(4)UNS Gas charges TEP for natural gas capacity used to supply one of TEP's generation facilities.

NOTE 6. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
There have been no significant changes to TEP's long-term commitments from those reported in its 20162023 Annual Report on Form 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 condensedoperations 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 Four Corners Generating Station
Endangered Species Act
On April 20, 2016, several environmental groups filed a lawsuit in the U.S. District Court for the District of Arizona against the Office of Surface Mining (OSM) and other federal agencies under the Endangered Species Act (ESA) alleging that the OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with a federal environmental review were not in accordance with applicable law. The environmental review was undertaken as part of the U.S. Department of the Interior’s review process necessary to allow for the effectiveness of lease amendments and related rights-of-way renewals for Four Corners. This review process also required separate environmental impact evaluations under the National Environmental Policy Act (NEPA) and culminated in the issuance of a Record of Decision justifying the agency action extending the life of Four Corners and the adjacent Navajo Mine. In addition, the lawsuit alleges that these federal agencies violated both the ESA and the NEPA in providing the federal approvals necessary to extend operations at Four Corners and Navajo Mine past July 6, 2016. The lawsuit seeks various forms of relief, including a finding that the federal defendants violated the ESA and the NEPA by issuing the Record of Decision, setting aside and remanding the Biological Opinion and Record of Decision, and enjoining the federal defendants from authorizing any elements of the Four Corners and Navajo Mine pending compliance with NEPA. In July 2016, the defendants answered the complaint and Arizona Public Service Company (APS), the operator of Four Corners, filed a motion to intervene in this matter. APS’ motion was granted in August 2016. In September 2016, Navajo Transitional Energy Company, LLC (NTEC), the company that owns the Navajo Mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC’s tribal sovereign immunity. In September 2017, the court granted NTEC’s motion to dismiss and dismissed the case with prejudice.
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 OSM challenging several unrelated mining plan modification approvals, including two issued in 2008 related to San Juan Coal Company’s (SJCC) San Juan mine. The petition alleges various NEPA violations against the OSM, including failure to provide requisite public notice and participation, and failure to analyze certain environmental impacts. WEG’s petition seeks various forms of relief, including voiding and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the approvals until they can demonstrate compliance with the NEPA, and enjoining operations at the affected mines. SJCC intervened in this matter and was granted its motion to sever its claims from the lawsuit and transfer venue to the U.S. District Court for the District of New Mexico, where this matter is now pending. In July 2016, the federal defendants filed a motion asking that the matter be voluntarily remanded to the OSM so the OSM may prepare a new environmental impact statement (EIS) under the NEPA regarding the impacts of the San Juan mine mining plan approval. In August 2016, the court issued an order granting the motion for remand to conduct further environmental analysis and complete an EIS by August 31, 2019. The order provided that the OSM’s decision approving the mining plan will remain in effect during this process, but that if the EIS is not completed by August 31, 2019, then the approved mine plan will immediately be vacated, absent further court order. TEP cannot currently predict the outcome of this matter or the range of its potential impact.
Claims Related to Springerville Generating Station Unit 1
In February 2016, TEP entered into an agreement with the Third-Party Owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (Agreement). In September 2016, TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



the Third-Party Owners’ undivided interest in Springerville Unit 1 for $85 million. As also provided for in the Agreement, TEP received $12.5 million from the Third-Party Owners in full satisfaction of all previously unreimbursed operating costs, which TEP recorded in Operating Revenues—Other on the Consolidated Statements of Income. Following the purchase, all outstanding disputes, pending litigation, and arbitration proceedings between TEP and the Third-Party Owners were dismissed with prejudice.
Mine Reclamation at GeneratingGeneration Facilities Not Operated by TEP
TEP pays ongoing mine reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is also liable for a portion of final mine reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $61 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The balance sheet reflected a total liability related to reclamation of $32 million as of September 30, 2017 and $26 million as of December 31, 2016.
Amounts recorded for final mine reclamation costs are subject to various assumptions, such asas: estimations of reclamation costs, the datescosts; timing of when final reclamation will occur,occur; and the expected inflation rate. As these assumptions change, TEP will prospectively adjustadjusts the expense amounts for final reclamation over the remaining term of the respective 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.
agreement. TEP’s PPFAC allows the Company to pass throughpass-through of final mine reclamation costs to retail customers as a component of fuel costs, to retail customers.costs. Therefore, TEP classifiesdefers these costs asexpenses until recovered from customers by recording a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the respective coal supply agreements andagreements. TEP recovers the regulatory asset through the PPFAC as final mine reclamation costs are paidfunded. After expiration of the related coal supply agreement, TEP will record its share of any change in the estimate of its final mine reclamation liability to its regulatory asset and reclamation liability.
TEP is liable for a portion of final mine reclamation costs for the mines at San Juan and Four Corners. TEP’s share of final mine reclamation costs at Four Corners is $6 million upon the expiration of the Four Corners coal supply agreement in 2031. TEP ceased operations at San Juan upon expiration of the coal suppliers.
FERC Compliance
supply agreement in 2022. In 2015 and 2016,March 2024, TEP self-reported toincreased the FERC Office of Enforcement (OE) that the Company had not timely filed certain FERC-jurisdictional agreements. TEP conducted comprehensive internal reviews of its compliance with the FERC filing requirements (Compliance Reviews) and made compliance filings with the FERC Office of Energy Market Regulation. This included the filing of several TSAs entered into between 2003 and 2015 that contained certain deviations from TEP’s standard service agreement form.
In 2016, the FERC issued orders related to the late-filed TSAs which directed TEP to issue time-value refunds to the counterparties to these TSAs (FERC Refund Orders). AsSan Juan final mine reclamation liability by $15 million as a result of a new final mine reclamation study. As of March 31, 2024,TEP’s remaining final mine reclamation liability at San Juan was $38 million. TEP established a trust to fund its share of estimated final mine reclamation costs at San Juan, which will remain in effect through the FERC Refund Orderscompletion of final mine reclamation activities currently projected to be 2040. See Note 1 for additional information on restricted cash relating to TEP's share of final mine reclamation and ongoing discussions with the OE, TEP recorded adecommissioning costs at San Juan.
TEP's aggregate liability for the time-value refunds with a corresponding offset in revenues on its financial statements in 2016. For the three and nine months ended September 30, 2016, Wholesale Revenues on the Condensed Consolidated Statements of Income reflected $9 million and $22 million, respectively,balance related to the time-value refunds. AsSan Juan and Four Corners final mine reclamation totaled $42 million and $29 million as of March 31, 2024, and December 31, 2016, Current Liabilities—2023, respectively, and was recorded in Other Noncurrent Liabilities on the Condensed Consolidated Balance Sheets reflected $5 million related to the time-value refunds.
In June 2016, to preserve its rights, TEP petitioned the U.S. Court of Appeals for the District of Columbia Circuit to review the FERC Refund Orders. In January 2017, TEP and one of the TSA counterparties entered into a settlement agreement regarding the FERC Refund Orders. In accordance with the agreement, the counterparty paid TEP $8 million, which TEP recorded in Other Income on the Condensed Consolidated Statements of Income and dismissed the appeal with prejudice in January 2017.
In May 2017, the FERC informed TEP that: (i) no further enforcement actions were necessary regarding the late-filed TSAs; and (ii) the related investigation was closed. As management no longer believed a loss was probable, TEP reversed the $5 million remaining balance related to potential time-value refunds in Current Liabilities—Other on the Condensed Consolidated Balance Sheets, offsetting Wholesale Revenues on the Condensed Consolidated Statements of Income.Sheets.
Performance Guarantees
TEP has joint generation participation agreements with participants at Navajo, San Juan, Four Corners and with Luna Generating Station (Luna)., which expire in 2041 and 2046, respectively. The participants in each of the generation facilities,at Four Corners and Luna, 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, thereThere is no maximum potential amount of future payments TEP could be required to make under the guarantees.Luna guarantee. The maximum potential amount of future payments on the non-defaulting parties is $250 million at Four Corners. As of September 30, 2017,March 31, 2024, there have been no such payment

defaults under either of the participation agreements.
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defaults under any of the participation agreements. The Navajo Generating Station and San Juan participation agreements expired in 2019 and 2022, respectively, but certain performance obligations continue through the decommissioning of both generation facilities. In the case of a default under either participation agreement, expires in 2019, San Juan in 2022, Four Corners in 2041, and Luna in 2046.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 condensed consolidated financial results. TEP expects to recover the cost of environmental compliance from its ratepayers.customers. TEP believes it is in material compliance with applicable environmental laws and regulations.regulations in all material respects.


NOTE 7. EMPLOYEE BENEFIT PLANS
Net periodic benefit cost includes the following components:
 Pension Benefits Other Postretirement Benefits
 Three Months Ended September 30,
(in millions)2017 2016 2017 2016
Service Cost$3
 $3
 $1
 $1
Interest Cost3
 4
 1
 1
Expected Return on Plan Assets(6) (5) (1) —
Amortization of Net Loss2
 1
 —
 —
Net Periodic Benefit Cost$2
 $3
 $1
 $2
Nine Months Ended September 30,
Pension BenefitsPension BenefitsOther Postretirement Benefits
Three Months Ended March 31,Three Months Ended March 31,
(in millions)2017 2016 2017 2016(in millions)2024202320242023
Service Cost$9
 $9
 $3
 $3
Non-Service Cost (1)
Interest Cost
Interest Cost
Interest Cost11
 11
 2
 2
Expected Return on Plan Assets(18) (17) (1) (1)
Amortization of Net Loss6
 5
 —
 —
Net Periodic Benefit Cost$8
 $8
 $4
 $4
CONTRIBUTIONS(1)The non-service components of net periodic benefit cost are included in Other, Net on the Condensed Consolidated Statements of Income.
TEP contributed $9 million during the nine months ended September 30, 2017, to the pension plans. No additional contributions are planned in 2017.


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



NOTE 8. SUPPLEMENTAL CASH FLOW INFORMATION
NON-CASH TRANSACTIONS
Other significant non-cash investing and financing activities that affected recognized assets and liabilities but did not result in cash receipts or payments were as follows:
 Nine Months Ended September 30,
(in millions)2017 2016
Net Cost of Removal Increase (Decrease) (1)
$(88) $3
Accrued Capital Expenditures18
 16
Additions to Utility Plant, Springerville Unit 1 Settlement (2)
—
 5
(1)
Non-cash Net Cost of Removal represents an accrual for future cost of retirement net of salvage values that does not impact earnings. In the 2017 Rate Order, the ACC authorized a new depreciation study for TEP modifying its depreciation reserves and rates. See Note 2 for additional information.
(2)
See Note 6 for additional information regarding the Springerville Unit 1 settlement.

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. Transfers between levels are recorded at the endTEP has no financial instruments categorized as Level 3.
13

Table of a reporting period. There were no transfers between levels in the periods presented.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. These assets and liabilities arebasis classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
measurement:
Level 1Level 2Total
(in millions)March 31, 2024
Assets
Cash Equivalents (1)
$8 $— $8 
Restricted Cash (1)
32 — 32 
Energy Derivative Contracts, Regulatory Recovery (2)
— 32 32 
Energy Derivative Contracts, No Regulatory Recovery (2)
— 29 29 
Total Assets40 61 101 
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)
— (47)(47)
Total Liabilities— (47)(47)
Total Assets (Liabilities), Net$40 $14 $54 
(in millions)December 31, 2023
Assets
Restricted Cash (1)
$34 $— $34 
Energy Derivative Contracts, Regulatory Recovery (2)
— 32 32 
Energy Derivative Contracts, No Regulatory Recovery (2)
— 3 3 
Total Assets34 35 69 
Liabilities
Energy Derivative Contracts, Regulatory Recovery (2)
— (30)(30)
Total Liabilities— (30)(30)
Total Assets (Liabilities), Net$34 $5 $39 
 Level 1 Level 2 Level 3 Total
(in millions)September 30, 2017
Assets 
Cash Equivalents(1)
$59
 $—
 $—
 $59
Restricted Cash(1)
8
 —
 —
 8
Energy Derivative Contracts, Regulatory Recovery(2)
—
 —
 1
 1
Energy Derivative Contracts, No Regulatory Recovery(2)
—
 —
 4
 4
Total Assets67
 —
 5
 72
Liabilities       
Energy Derivative Contracts, Regulatory Recovery(2)
—
 (7) —
 (7)
Energy Derivative Contracts, No Regulatory Recovery(2)
—
 —
 (1) (1)
Interest Rate Swap(3)
—
 (1) —
 (1)
Total Liabilities—
 (8) (1) (9)
Total Assets (Liabilities), Net$67
 $(8) $4
 $63
(1)Cash Equivalents and Restricted Cash represent amounts held in money market funds, which approximate 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 and forward power purchase and sale contracts entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets.
17
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



(in millions)December 31, 2016
Assets 
Cash Equivalents(1)
$23
 $—
 $—
 $23
Restricted Cash(1)
7
 —
 —
 7
Energy Derivative Contracts, Regulatory Recovery(2)
—
 3
 —
 3
Energy Derivative Contracts, No Regulatory Recovery(2)
—
 —
 2
 2
Total Assets30
 3
 2
 35
Liabilities       
Energy Derivative Contracts, Regulatory Recovery(2)
—
 (2) (1) (3)
Interest Rate Swap(3)
—
 (2) —
 (2)
Total Liabilities—
 (4) (1) (5)
Total Assets (Liabilities), Net$30
 $(1) $1
 $30
(1)
Cash Equivalents and Restricted Cash represent amounts held in money market funds, insured cash sweep accounts, and certificates of deposit valued at cost, including interest, which approximates fair market value. Cash Equivalents are included in Cash and Cash Equivalents on the Condensed Consolidated Balance Sheets. Restricted cash is included in Investments and Other Property and in Current Assets—Other on the Condensed Consolidated Balance Sheets.
(2)
Energy Derivative Contracts include gas swap agreements (Level 2), and forward purchased power and sales contracts (Level 3) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the Condensed Consolidated Balance Sheets. The valuation techniques are described below.
(3)
The Interest Rate Swap is valued using an income valuation approach based on the 6-month London Interbank Offered Rate and is included in Derivative Instruments on the Condensed Consolidated Balance Sheets.
All energy derivative contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. TEP presents derivatives on a gross basis in the balance sheet. The tables below present the potential offset of counterparty netting and cash collateral.
 Gross Amount Recognized in the Balance Sheets Gross Amount Not Offset in the Balance Sheets Net Amount
  Counterparty Netting of Energy Contracts Cash Collateral Received/Posted 
(in millions)September 30, 2017
Derivative Assets       
Energy Derivative Contracts$5
 $2
 $—
 $3
Derivative Liabilities       
Energy Derivative Contracts(8) (2) —
 (6)
Interest Rate Swap(1) —
 —
 (1)
(in millions)December 31, 2016
Derivative Assets       
Energy Derivative Contracts$5
 $2
 $—
 $3
Derivative Liabilities       
Energy Derivative Contracts(3) (2) —
 (1)
Interest Rate Swap(2) —
 —
 (2)
collateral:
Gross Amount Recognized in the Balance SheetsGross Amount Not Offset in the Balance SheetsNet Amount
Counterparty Netting of Energy ContractsCash Collateral Received/Posted
(in millions)March 31, 2024
Derivative Assets
Energy Derivative Contracts$61 $21 $— $40 
Derivative Liabilities
Energy Derivative Contracts(47)(21)— (26)
(in millions)December 31, 2023
Derivative Assets
Energy Derivative Contracts$35 $15 $— $20 
Derivative Liabilities
Energy Derivative Contracts(30)(15)— (15)
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 TEP'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

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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 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 real power 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'sTEP'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 loss expected to be reclassified to earnings within the next twelve months is estimated to be$1 million.
The realized losses from its cash flow hedges are shown in the following table:
 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2017 2016 2017 2016
Capital Lease Interest Expense$—
 $—
 $1
 $1
As of September 30, 2017, the total notional amount of the interest rate swap was $18 million.
Energy Derivative Contracts, Regulatory Recovery
TEP recordsenters 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 on energy purchase contracts that are recoverable through the PPFAC mechanism on the balance sheetdeferred as a regulatory asset or liability. The table below presents the unrealized gains and losses recorded to a regulatory asset or liability rather than reporting the transaction in the income statement orbalance sheet:
Three Months Ended March 31,
(in millions)20242023
Unrealized Net Gain (Loss) (1)
$(14)$(42)
(1)For the three months ended March 31, 2024 and 2023, unrealized net loss on regulatory recoverable derivative contracts was primarily due to decreases in the statementforward market prices of other comprehensive income, as shown in the following table:natural gas.
15

 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2017 2016 2017 2016
Unrealized Net Gain (Loss) Recorded to Regulatory (Assets) Liabilities$(1) $1
 $(6) $10
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    
Energy Derivative Contracts, No Regulatory Recovery
TEP enters into certain energy contracts that qualify asare considered derivatives but do not meet thequalify for regulatory recovery criteria.recovery. The Company records unrealized gains and losses for these contracts in the income statement unless a normal purchase or normal sale election is made. For contracts that meet the trading definition as defined in the PPFAC plan of administration, TEP must share 10% of any realized gains with retail customers through the PPFAC mechanism. The table below presents amounts recorded in Operating Revenues on the Condensed Consolidated Statements of Income:
Three Months Ended March 31,
(in millions)20242023
Operating Revenues$27 $13 
Derivative Volumes
As of September 30, 2017,March 31, 2024, TEP had energy contracts that will settle on various expiration dates through 2020.2029. The following table presents volumes associated with the energy contracts were as follows:
 September 30, 2017 December 31, 2016
Power Contracts GWh3,840
 2,610
Gas Contracts BBtu29,261
 12,355

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



Level 3 Fair Value Measurements
The following tables provide quantitative information regarding significant unobservable inputs in TEP’s Level 3 fair value measurements:
 Valuation Approach Fair Value of   Range of Unobservable Input
  Assets Liabilities Unobservable Inputs 
(in millions)September 30, 2017
Forward Power ContractsMarket approach $5
 $(1) Market price per MWh $17.55
 $34.05
(in millions)December 31, 2016
Forward Power ContractsMarket approach $2
 $(1) Market price per MWh $20.90
 $40.00
Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC mechanism and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.
The following table presents a reconciliation of changes in the fair value of net assets and liabilities classified as Level 3 in the fair value hierarchy, and the gains (losses) attributable to the change in unrealized gains (losses) relating to assets (liabilities) still held at the end of the period:
 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2017 2016 2017 2016
Beginning of Period$4
 $3
 $1
 $(2)
Gains (Losses) Recorded       
Regulatory Assets or Liabilities, Derivative Instruments1
 1
 3
 3
Wholesale Revenues—
 —
 4
 3
Settlements(1) (1) (4) (1)
End of Period$4
 $3
 $4
 $3
        
Gains (Losses), Assets (Liabilities) still held$—
 $—
 $4
 $3
contracts:
March 31, 2024December 31, 2023
Power Contracts GWh5,468 1,449 
Gas Contracts BBtu97,012 89,105 
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 measurementmeasurements 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. In the event that(iv) unfavorable changes in parties' assessments of each other's credit strength. If such credit events were to occur, the Company,TEP, or its counterparties, wouldcould have to provide certain credit enhancements in the form of cash, a LOC,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 fair 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 $21$31 million as of September 30, 2017,March 31, 2024, compared with $8$28 million as of December 31, 2016. As2023. TEP had no cash posted as collateral to provide credit enhancement as of September 30, 2017, TEP had no LOCs as credit enhancements with its counterparties. If the credit risk contingent features were triggered on September 30, 2017,March 31, 2024, and December 31, 2023. TEP would have been required to post an additional $21$31 million and $28 million of collateral of which $14if the credit risk contingent features had been triggered on March 31, 2024, and December 31, 2023, respectively. TEP had $7 million relates toand $13 million in outstanding net payable balances for settled positions.

20
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)    



March 31, 2024, and December 31, 2023, respectively.
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. TEP uses the following methods and assumptions for estimating the fair value of financial instruments:
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.
For long-term debt, TEP uses quoted market prices, when available, or calculates the present value
16

Table of the remaining cash flows at the balance sheet date. When calculating present value, the Company uses current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. TEP considers the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. The Company also incorporates the impact of its own credit risk using a credit default swap rate.Contents
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)    
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 HierarchyNet Carrying ValueFair Value
(in millions)March 31, 2024December 31, 2023March 31, 2024December 31, 2023
Liabilities
Long-Term Debt, including Current MaturitiesLevel 2$2,397 $2,397 $2,085 $2,127 

NOTE 9. SUPPLEMENTAL CASH FLOW INFORMATION
 Fair Value Hierarchy Face Value Fair Value
(in millions) September 30, 2017 December 31, 2016 September 30, 2017 December 31, 2016
Liabilities         
Long-Term Debt, including Current MaturitiesLevel 2 $1,466
 $1,466
 $1,546
 $1,472
NON-CASH TRANSACTIONS

NOTE 10. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
TEP considers the applicabilityOther significant non-cash investing and impact of all Accounting Standard Updates (ASU) issued by the Financial Accounting Standards Board (FASB). The following updates have been issued, but have not yet been adopted by TEP. Updates not listed below were assessed and either determined to not be applicable or are expected to have a minimal impact on TEP's condensed consolidated financial position, results of operations, or disclosures.
REVENUE FROM CONTRACTS WITH CUSTOMERS
In May 2014, the FASB issued an ASU intended to enable users of financial statements to better understand and consistently analyze an entity's revenues across industries and transactions. Under the new standard,financing activities that resulted in recognition of revenue occurs when a customer obtains control of promised goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. TEP does not expect the adoption of this new guidance to affect revenue recognition for tariff-based sales to retail and wholesale customers, which represent TEP's primary source of revenue. Accordingly, TEP does not expect the adoption of this standard to have a material effect on its financial statements. However, the presentation and disclosure requirements of the guidance will result in a change in the presentation of revenues on TEP's consolidated statements of income as well as expanded disclosures. The guidance is effective for annual and interim periods beginning January 1, 2018 and permits two implementation approaches: (i) retrospective application; or (ii) modified retrospective application by recognizing the cumulative effect of initially applying the guidance as an adjustment to the opening balance of retained earnings on the date of adoption supplemented by additional disclosures. TEP plans to adopt this standard on January 1, 2018, using the modified retrospective approach.
LEASES
In February 2016, the FASB issued an ASU that will require the recognition of leased assets and liabilities by lesseesbut did not result in cash receipts or payments were as follows:
Three Months Ended March 31,
(in millions)20242023
Accrued Capital Expenditures$47 $47 
Renewable Energy Credits5 6 
Net Cost of Removal Increase (Decrease) (1)
4 (3)
Asset Retirement Obligations Increase (Decrease)(1)(1)
(1)Represents an accrual for those leases classified as operating leases under current GAAP. The standard is effective for periods beginning January 1, 2019, and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. TEP is evaluating thefuture cost of retirement net of salvage values that does not impact of this update to its financial statements and disclosures.
RESTRICTED CASH
In November 2016, the FASB issued an ASU that will require entities to show the changes in the total of cash, cash equivalents, and restricted cash or restricted cash equivalents in the cash flow statement. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the cash flow statement. The standard is effective for annual and interim periods beginning January 1, 2018, and is to be applied using a retrospective approach. Early adoption is permitted. TEP expects to early adopt the new standard effective December 31, 2017. The adoption of the standard

earnings.
21
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)s

will impact the presentation of the cash flow statement but will not have an impact on TEP's financial position or results of operations.
COMPENSATION—RETIREMENT BENEFITS
In March 2017, the FASB issued an ASU to improve the presentation of net periodic benefit cost for pension and other postretirement benefits. The guidance requires employers to retrospectively present the service cost component in the same line item as other compensation costs and to present the non-service cost components of net periodic benefit costs separately and outside a subtotal of operating income. The ASU is effective for annual and interim periods beginning January 1, 2018. Early adoption is permitted. TEP does not intend to early adopt the ASU and will implement the standard update in the first quarter of 2018. The Company does not expect that its adoption will have a material impact on its financial position or results of operations.
DERIVATIVES AND HEDGING
In August 2017, the FASB issued an ASU that enables entities to better align their risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance and the presentation of hedge results. The standard update expands an entity's ability to apply hedge accounting to nonfinancial and financial risk components and simplify fair value hedges of interest rate risk. The new guidance eliminates the requirement to separately measure and report hedge ineffectiveness and generally requires the entire change in the fair value of a hedging instrument to be presented in the same income statement line as the hedged item. The amendments to the update also ease hedge documentation and effectiveness assessments requirements under previous guidance. The standard is effective for annual and interim periods beginning January 1, 2019. Early adoption is permitted. TEP is evaluating the impact of this update to its financial statements and disclosures.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for TEP. It includes the following:
•outlook and strategies;
operating results in the third quarter and first nine months of 2017 compared with the same periods in 2016;
•factors affecting our results of operations and outlook;operations;
•results of operations;
•liquidity and capital resources, including contractual obligations, capital expenditures, income tax position, and environmental matters;
•critical accounting policies and estimates; and
recent•new accounting pronouncements.standards issued and not yet adopted.
Management’s Discussion and Analysis includes financial information prepared in accordance with GAAP financial measures. It also includes non-GAAP financial measures which should be viewed as a supplement to, and not a substitute for, financial measures presented in accordance with GAAP. Non-GAAP financial measures as presented herein may not be comparable to similarly titled measures used by other companies.
Management’s Discussion and Analysis should be read in conjunction with the condensed consolidated financial statementsCondensed Consolidated Financial Statements and accompanying notes that appearNotes 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 seek or anticipate, see Forward-Looking Information at the front of this reportForm 10-Q and Risk Factors in Part 1, Item 1A of our 20162023 Annual Report on Form 10-K, and in Part II, Item 1A of this Form 10-Q.
References in this reportManagement's Discussion and Analysis to "we""we," "our," and "our""us" are to TEP.


OUTLOOK AND STRATEGIES
TEP'sOur 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, regulations, and regulations;policies; and (iv) other regulatory factors.
and legislative actions. Our plans and strategies include the following: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; and (ii) updated rates that provide more accurate price signals and a more equitable allocation of costs to our customers; and (iii) the abilitycustomers.
•Continuing our transition to continue providing safe and reliable service.
Continuing to focus on our long-term resource diversification strategy, including shifting from coal to natural gas, renewables, anda less carbon-intensive energy efficiencyportfolio, 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. ThisIn November 2023, we announced our new aspirational goal of net zero direct GHG emissions by 2050. The new goal keeps us on pace to reduce carbon emissions by 80% compared to 2005 by 2035. The establishment of this additional target reinforces our commitment to decarbonize over the long-term, strategy includes a target of meeting 30% of our customers’while preserving customer reliability and affordability. These goals may be impacted by various federal and state energy needs with non-carbon emitting resources by 2030.policies, including policies currently under consideration.
•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.
2017 Operational and Financial Highlights
Management's Discussion and Analysis includes the following notable items:
In February 2017, the ACC issued a decision in TEP’s rate case approving a non-fuel base rate increase of $81.5 million, a cost of equity component of 9.75%, and an equity ratio of approximately 50%.Performance - The new rates took effect on February 27, 2017.
In May 2017, the FERC informed TEP that no further enforcement actions were necessary as the investigation related to the FERC Refund Orders was closed. Previously, in January 2017 TEP and a counterparty, who had been a recipient

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of time-value refunds in compliance with the FERC Refund Orders, entered into a settlement agreement resulting in the counterparty paying TEP $8 million and TEP dismissing a previously filed appeal.
In June 2017, the Navajo Nation approved a land lease extension that allows Navajo to operate through December 2019 and decommissioning activities to begin thereafter. As a result of the planned early retirement, $52 million of Navajo’s NBV and other related costs were reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets.
In August 2017, TEP submitted an Application to the PDEQ related to a generation modernization project at Sundt. In conjunction with the project, TEP will discontinue operation of Sundt Units 1 and 2 by the end of 2020. As a result of the planned early retirement, $32 million of the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets.
In October 2017, TEP entered into a 20-year Tolling PPA with Salt River Project Agricultural Improvement and Power District (SRP) to purchase and receive all 550 MW of capacity, power, and ancillary services from Unit 2 of Gila River Generating Station (Gila River). The Tolling PPA will allow TEP to continue to move toward its long-term goal of resource diversification. TEP’s obligations under the agreement are contingent upon SRP's acquisition of Gila River Units 1 and 2, which is expected to be completed in the first quarter of 2018.

RESULTS OF OPERATIONS
The following discussion provides the significant items that affected TEP's results of operations in the third quarter and first ninethree months of 20172024 compared with the same periods in 2016. The significant items affecting net income are presented on an after-tax basis.first three monthsof2023
The third quarter of 2017 compared with the third quarter of 2016
TEPWe reported net income of $82$51 million in the third quarter first three monthsof 20172024 compared with $72net income of $47 million in the third quarterfirst three months of 2016.2023. The increase of $10$4 million, or 13.9%9%, was primarily due to:to (net of tax):
•$1811 million in higher margin from retail revenue primarily due to an increase in rates as approved in the 20172023 Rate Order; partially offset by lower usage as a result of less favorable weather and lower LFCR revenues;
•$57 million in higher net income associated with late-filed TSAs. See Note 6margin from wholesale transactions primarily due to an increase in revenues realized from wholesale trading as defined in the PPFAC plan of Notesadministration; partially offset by a decrease in long-term wholesale volumes due to Condensed Consolidated Financial Statementsless favorable market conditions and the expiration of certain contracts; and
•$3 million in Part I, Item 1higher AFUDC due to an increase in eligible construction expenditures.
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Table of this Form 10-Q.Contents
The increase was partially offset by:
•$8 million in lower other revenues related to a September 2016 settlement involving Springerville Unit 1. For further information related to the settlement, see Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q; and
$2 million in higher depreciation and amortization expenses.expense primarily due an increase in depreciation rates as approved in the 2023 Rate Order;
The first nine months of2017 compared with the first nine monthsof2016
TEP reported net income of $164•$4 million in the first nine months of 2017 compared with net income of $111 million in the first nine months of 2016. The increase of $53 million, or 47.7%, waslower margin from transmission revenue primarily due to:to a regulatory decision approving a credit to retail customers for certain transmission revenues;
•$403 million in higher retail revenuebase operations and maintenance expenses primarily due to an increase in rates as approved in the 2017 Rate Orderoutside service expenses and an increase in usage due to favorable weather;higher maintenance costs at our generation facilities; and
•$21 million in higher net income associated with late-filed TSAs. See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q; and
$6 million in higher wholesale revenue primarily due to favorable pricing on wholesale contracts in 2017.

The decrease was partially offset by:
$8 million in lower other revenuesinterest income due to a reduction in under-recovered PPFAC costs.

FACTORS AFFECTING RESULTS OF OPERATIONS
Several factors affect our current and future results of operations. The most significant factors are related to a September 2016 settlement involving Springerville Unit 1. For further information related to the settlement, see Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q; and
$6 million in higher depreciation and amortization expenses.
Retail Sales and Revenues
The following tables provide a summary of retail kWh sales, a reconciliation of Retail Revenues from Retail Margin Revenues,regulatory matters, generation resource strategy, and weather datapatterns.
Regulatory Matters
We are subject to comprehensive regulation. The discussion below contains material developments in those matters.
2023 Rate Order
In August 2023, the ACC issued a rate order for new rates that took effect September 1, 2023. Provisions of the third quarter2023 Rate Order include, but are not limited to:
•a non-fuel retail revenue increase of 2017$100 million over test year non-fuel retail revenues;
•a 6.93% return on original cost rate base of $3.6 billion, which includes a return on equity of 9.55% and 2016an average cost of debt of 3.82%; and
•approval to recover costs of changes in generation resources, including the addition of Oso Grande in rates.
Generation Resource Strategy
Our long-term resource planning strategy is to continue our transition to a less carbon-intensive energy portfolio by expanding renewable energy, energy storage, and natural gas resources while reducing reliance on coal-fired generation resources. In November 2023, we filed our 2023 IRP with the ACC, which outlines our plan to expand our clean energy portfolio to support anticipated growth and maintain affordable, reliable service as we work towards a new aspirational goal of net zero direct GHG emissions by 2050. The new goal keeps us on pace to reduce our carbon emissions by 80% compared to 2005 by 2035.
As a result of our 2022 All-Source Request for Proposal (ASRFP), we entered into an EPC agreement to develop Roadrunner Reserve I and a renewable PPA with Wilmot Energy Center II (Wilmot II). Wilmot II will have 100 MW of solar capacity accompanied by 100 MW of battery storage with an anticipated in service date in 2026. In December 2023, we issued another ASRFP based on the resource needs outlined in our 2023 IRP, including natural gas-fired generation, targeting in-service dates of 2026 through 2027.
In April 2024, as a result of our 2022 ASRFP, we entered into a PPA with Winchester Solar I, LLC (Winchester). Winchester will have 80 MW of solar capacity accompanied by 80 MW of battery storage with an anticipated in service date of March 2027.
Our existing coal-fired generation fleet faces a number of uncertainties affecting 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 policies, and, for jointly-owned facilities, the first nine monthswillingness of 2017other owners to continue their participation. Given this uncertainty, we expect to exit all ownership interests in coal-fired generation facilities by 2032. We will seek regulatory recovery for amounts, if any, that would not otherwise be recovered as a result of these actions. The execution of our 2023 IRP is dependent on obtaining regulatory recovery in future rate proceedings.
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Oso Grande
Production Tax Credits
PTCs are per kWh federal tax credits earned for electricity generated using qualified energy resources, which can be claimed for a 10-year period once a qualifying facility is placed in service. In May 2021, Oso Grande, a qualified energy resource, was placed in service. While costs associated with operating the facility are recorded throughout the year, PTCs are recognized through the effective tax rate provision and 2016, respectively.

Retail Revenues were $340 millionare primarily recognized in the third quarter due to weather patterns that contribute to seasonal fluctuations in taxable earnings. We recorded PTCs of 2017 compared with $320approximately $4 million in each of the three months ended March 31, 2024, and 2023. The PTC rate published by the IRS for electricity produced by a qualified facility using wind placed in service prior to 2022 was $0.028 for 2023.
Electricity generated from Oso Grande depends heavily on wind conditions. If such conditions vary from our estimates, or if any operational constraints exist, the project's electricity generation and associated PTCs may be substantially different compared to prior periods. As of September 1, 2023, Oso Grande is included in rates as part of the 2023 Rate Order.
Weather Patterns
Changing weather patterns and other factors cause seasonal fluctuations in sales of power. Our retail sales are highest in the second and third quarter of 2016. Retail Margin Revenues (non-GAAP) were $234 millionthe year when cooling demand is higher, which results in higher revenue during this period. By contrast, lower sales of power occur during the first and fourth quarters of the year, due to mild winter weather in our retail service territory. Our operating costs are generally consistent throughout the year which produces higher operating income in the third quarter of 2017 compared with $207 million in the third quarter of 2016.
 Three Months Ended September 30, Increase (Decrease)
 2017 2016 Amount Percent
Retail Sales by Customer Class (kWh in millions)
       
Residential1,361
 1,344
 17
 1.3 %
Commercial653
 627
 26
 4.1 %
Industrial559
 590
 (31) (5.3)%
Mining251
 245
 6
 2.4 %
Public Authorities3
 6
 (3) (50.0)%
Total Retail Sales by Class2,827
 2,812
 15
 0.5 %
Retail Revenues (in millions)
       
Residential$119
 $101
 $18
 17.8 %
Commercial67
 60
 7
 11.7 %
Industrial31
 30
 1
 3.3 %
Mining11
 10
 1
 10.0 %
Public Authorities—
 —
 —
 — %
Retail Margin Revenues by Class228
 201
 27
 13.4 %
LFCR Revenues6
 5
 1
 20.0 %
Other Retail Margin Revenues—
 1
 (1) (100.0)%
Retail Margin Revenues (non-GAAP) (1)
234
 207
 27
 13.0 %
Fuel and Purchased Power Revenues92
 98
 (6) (6.1)%
DSM and RES Surcharge Revenues14
 15
 (1) (6.7)%
Total Retail Revenues (GAAP)$340
 $320
 $20
 6.3 %
Average Retail Margin Rate by Class (cents/kWh)
       
Residential8.74
 7.51
 1.23
 16.4 %
Commercial10.26
 9.57
 0.69
 7.2 %
Industrial5.55
 5.08
 0.47
 9.3 %
Mining4.38
 4.08
 0.30
 7.4 %
Public Authorities (2)
8.28
 5.76
 2.52
 43.8 %
Average Retail Margin Rate by Class8.07
 7.15
 0.92
 12.9 %
Total Average Retail Margin Rate (3)
8.28
 7.36
 0.92
 12.5 %
Average Fuel and Purchased Power Rate3.25
 3.49
 (0.24) (6.9)%
Average DSM and RES Surcharge Rate0.50
 0.53
 (0.03) (5.7)%
Total Average Retail Rate12.03
 11.38
 0.65
 5.7 %
Weather Data       
Cooling Degree Days       
Actual1,006
 962
 44
 4.6 %
10-year Average1,018
 1,018
 *
 *

Retail Revenues were $820 million in the first nine months of 2017 compared with $781 million in the first nine months of 2016. Retail Margin Revenues (non-GAAP) were $561 million in the first nine months of 2017 compared with $500 million in the first nine months of 2016.
 Nine Months Ended September 30, Increase (Decrease)
 2017 2016 Amount Percent
Retail Sales by Customer Class (kWh in millions)
       
Residential3,066
 2,990
 76
 2.5 %
Commercial1,671
 1,633
 38
 2.3 %
Industrial1,487
 1,537
 (50) (3.3)%
Mining745
 743
 2
 0.3 %
Public Authorities13
 23
 (10) (43.5)%
Total Retail Sales by Class6,982
 6,926
 56
 0.8 %
Retail Revenues (in millions)
       
Residential$268
 $226
 $42
 18.6 %
Commercial162
 146
 16
 11.0 %
Industrial80
 80
 —
 — %
Mining29
 27
 2
 7.4 %
Public Authorities1
 1
 —
 — %
Retail Margin Revenues by Class540
 480
 60
 12.5 %
LFCR Revenues17
 14
 3
 21.4 %
DSM Performance Bonus2
 2
 —
 — %
Other Retail Margin Revenues2
 4
 (2) (50.0)%
Retail Margin Revenues (non-GAAP) (1)
561
 500
 61
 12.2 %
Fuel and Purchased Power Revenues219
 243
 (24) (9.9)%
DSM and RES Surcharge Revenues40
 38
 2
 5.3 %
Total Retail Revenues (GAAP)$820
 $781
 $39
 5.0 %
Average Retail Margin Rate by Class (cents/kWh)
       
Residential8.74
 7.56
 1.18
 15.6 %
Commercial9.69
 8.94
 0.75
 8.4 %
Industrial5.38
 5.20
 0.18
 3.5 %
Mining3.89
 3.63
 0.26
 7.2 %
Public Authorities (2)
7.56
 5.67
 1.89
 33.3 %
Average Retail Margin Rate by Class7.73
 6.93
 0.80
 11.5 %
Total Average Retail Margin Rate (3)
8.03
 7.22
 0.81
 11.2 %
Average Fuel and Purchased Power Rate3.14
 3.51
 (0.37) (10.5)%
Average DSM and RES Surcharge Rate0.57
 0.55
 0.02
 3.6 %
Total Average Retail Rate11.74
 11.28
 0.46
 4.1 %
Weather Data       
Cooling Degree Days       
Actual1,592
 1,431
 161
 11.3 %
10-year Average1,502
 1,491
 *
 *
Heating Degree Days       
Actual614
 629
 (15) (2.4)%
10-year Average739
 773
 *
 *
* Not meaningful
(1)
Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude revenues collected from retail customers that are directly

offset by expenses recorded in other line items. We believe the change in Retail Margin Revenues between periods provides useful information for investorssecond and analysts because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues from kWh sales, LFCR Revenues, DSM Performance Bonus, and certain Other Retail Margin Revenues available to cover the non-fuel operating expenses of our core utility business.
(2)
Calculated on unrounded data and may not correspond exactly to data shown in table.
(3)
Total Average Retail Margin Rate includes revenue related to LFCR Revenues, DSM Performance Bonus, and Other Retail Margin Revenues included in Retail Margin Revenues.
Retail Revenues increased in the third quarter and in the first nine months of 2017 when compared with the same periods in 2016 primarily due to higher retail margin revenues related to an increase in rates as approved in the 2017 Rate Order and an increase in usage due to favorable weatherlower operating income in the first and second quartersfourth quarter. As a result, seasonal fluctuations affect the comparability of 2017. The increases were partially offset byour results of operations.
Interest Rates
See Part II, Item 7A in our 2023 Annual Report on Form 10-K and Part I, Item 3 of this Form 10-Q for information regarding interest rate risk and its impact on earnings.

RESULTS OF OPERATIONS
Significant drivers of our results of operations that do not have a decrease in Fuel and Purchased Power Revenuessignificant impact on net income include:
•Cost Recovery Mechanisms — We record operating revenue related to reduced recoveries due to lowercost recovery mechanisms that allow for more timely recovery of fuel and purchased power costs and certain operations and maintenance costs between rate case proceedings. These mechanisms, which include PPFAC, rates.the RES 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 the PPFAC mechanism.cost recovery mechanisms.
•Short-Term Wholesale Sales — Revenues
 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2017 2016 2017 2016
Long-Term Wholesale 
$11
 $6
 $30
 $23
Short-Term Wholesale25
 26
 73
 57
Transmission8
 9
 22
 23
Transmission Refunds (1)
—
 (9) 5
 (22)
Total Wholesale Revenues$44
 $32
 $130
 $81
(1)
In 2016, FERC ordered TEP to make refunds associated with various late-filed TSAs for the time period during which rates were charged without FERC authorization. In May 2017, FERC informed TEP that no further enforcement actions were necessary as the related investigation was closed. See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on the FERC Refund Orders.
Wholesale Revenues increased by $12 million, or 37.5%, and $49 million, or 60.5%, in the third quarter and first nine months of 2017, respectively, compared with the same periods in 2016. The increases were primarily due to: (i) time-value FERC ordered refunds in 2016 and the reversal of accrued refunds in May 2017, both related to late-filed TSAs; (ii) favorable commodity pricing on theshort-term wholesale market; (iii) a wholesale contract that commenced January 2017; and (iv) an increase in Short-Term Wholesale volumes in the first quarter of 2017.
Short-Term Wholesale Revenuessales are primarily related to ACC jurisdictional generation assets and are returned to retail customers by crediting theoffsetting revenues against fuel and purchased power costs eligible for recovery through the PPFAC.PPFAC mechanism.
Other Revenues
 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2017 2016 2017 2016
Springerville Units 3 and 4 (1)
$23
 $21
 $61
 $59
Miscellaneous10
 21
 26
 35
Total Other Revenues$33
 $42
 $87
 $94
(1)
Represents revenues and reimbursements to TEP from Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit•Springerville Units 3 and SRP, the owner of Springerville Unit 4, related to the operation of these generation facilities.
Other Revenues decreased by $9 million, or 21.4%, and $7 million, or 7.4%, in the third quarter4 — Operations and first nine months of 2017, respectively, compared with the same periods in 2016. The decreases were primarily related to a September 2016 settlement involving Springerville Unit 1. See Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for further information related to the settlement.
Other Revenues includes: (i) reimbursementsmaintenance expenses related to Springerville Units 3 and 4; (ii) inter-company revenues from TEP's affiliates, UNS Gas4 are reimbursed by Tri-State Generation and UNS Electric, for corporate services provided by TEP; and (iii) miscellaneous service-related revenues such as rent on power pole attachments, damage claims, and customer late fees.

Operating Expenses
Generating Output and Fuel and Purchased Power Expense
TEP’s fuel and purchased power expense and energy resources are detailed inTransmission Association, Inc, the following tables:
 
Generation and Purchased
Power (kWh)
 
Fuel and Purchased Power
Expense
 Three Months Ended September 30,
(in millions)2017 2016 2017 2016
Coal-Fired Generation2,212
 2,369
 $56
 $53
Gas-Fired Generation1,073
 1,060
 34
 33
Utility Owned Renewable Generation21
 17
 —
 —
Reimbursed Fuel Expense, Springerville Units 3 and 4 (1)
—
 —
 2
 1
Total Generation3,306
 3,446
 92
 87
Purchased Power, Non-Renewable587
 444
 29
 19
Purchased Power, Renewable158
 160
 10
 11
Total Purchased Power745
 604
 39
 30
Transmission and Other PPFAC Recoverable Costs—
 —
 10
 7
Increase (Decrease) to Reflect PPFAC Recovery Treatment—
 —
 (9) 5
Total Generation and Purchased Power4,051
 4,050
 $132
 $129
Less Line Losses and Company Use248
 224
    
Total Power Sold3,803
 3,826
    
 Nine Months Ended September 30,
(in millions)2017 2016 2017 2016
Coal-Fired Generation5,764
 5,958
 $138
 $139
Gas-Fired Generation2,348
 2,711
 76
 74
Utility Owned Renewable Generation65
 51
 —
 —
Reimbursed Fuel Expense, Springerville Units 3 and 4 (1)
—
 —
 4
 4
Total Generation8,177
 8,720
 218
 217
Purchased Power, Non-Renewable1,912
 1,022
 75
 35
Purchased Power, Renewable525
 525
 32
 37
Total Purchased Power2,437
 1,547
 107
 72
Transmission and Other PPFAC Recoverable Costs—
 —
 27
 18
Increase (Decrease) to Reflect PPFAC Recovery Treatment—
 —
 (24) 19
Total Generation and Purchased Power10,614
 10,267
 $328
 $326
Less Line Losses and Company Use613
 575
    
Total Power Sold10,001
 9,692
    
(1)
Springerville Units 3 and 4 Fuel Expense is reimbursed by Tri-State and SRP.
Fuel and Purchased Power Expense increased by $3 million, or 2.3%, and $2 million, or 0.6% in the third quarter and first nine monthslessee of 2017, respectively, compared with the same periods in 2016. The increases were primarily due to an increase in Purchased Power volumes used to compensate for the decrease in generation volumes and an increase in average fuel cost per kWh (see table below). The increases were partially offset by the reduction in recovery of the PPFAC costs as a result of changes in the PPFAC rates. See Note 2 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information on the PPFAC mechanism.

The table below summarizes average fuel cost of generated and purchased power per kWh:
 Three Months Ended September 30, Nine Months Ended September 30,
(cents per kWh)2017 2016 2017 2016
Coal2.54
 2.23
 2.40
 2.34
Gas3.16
 3.07
 3.23
 2.73
Purchased Power, Non-Renewable4.88
 4.16
 3.93
 3.11
Purchased Power, Renewable6.48
 6.75
 6.10
 6.99
All Resources (1)
3.71
 3.23
 3.52
 3.17
(1)
Calculated on unrounded data and may not correspond exactly to data shown in Generation Output and Fuel and Purchased Power Expense table above.
Operations and Maintenance Expense
The table below summarizes the items included in Operations and Maintenance Expense:
 Three Months Ended September 30, Nine Months Ended September 30,
(in millions)2017 2016 2017 2016
Reimbursed Expenses, Springerville Units 3 and 4 (1)
$18
 $15
 $44
 $40
Reimbursed Expenses, Customer Funded Renewable Energy and DSM Programs (2)
8
 9
 21
 21
Other (3)
64
 65
 191
 199
Total Operations and Maintenance Expense$90
 $89
 $256
 $260
(1)
Expenses related to Springerville Units 3 and 4 are reimbursed with corresponding amounts recorded in Other Revenue.
(2)
These expenses are collected from customers and the corresponding amounts are recorded in Retail Revenue.
(3)
Includes the Third-Party Owners' share of expenses related to Springerville Unit 1 for the first nine months of 2016. See Note 6 for additional information regarding the Springerville Unit 1 settlement.
There were no significant changes to Operations and Maintenance Expense in the third quarter of 2017 compared with the same period in 2016.
Operations and Maintenance Expense decreased by $4 million, or 1.5%, in the first nine months of 2017 compared with the same period in 2016. The decrease was primarily due to a decrease in maintenance expense related to planned outages in the first quarter of 2016 and a sales tax refund in the second quarter of 2017.

FACTORS AFFECTING RESULTS OF OPERATIONS
Regulatory Matters
TEP is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Part II, Item 7 of our 2016 Annual Report on Form 10-K and new regulatory matters occurring in 2017.
2017 Rate Order
In February 2017, the ACC issued a rate order in the rate case filed by TEP in November 2015. TEP's rate filing was based on a test year ended June 30, 2015. The 2017 Rate Order approved new rates that went into effect on February 27, 2017.
The provisions of the 2017 Rate Order include, but are not limited to:
a non-fuel base rate increase of $81.5 million which includes $15 million of operating costs related to the 50.5% undivided interest in Springerville Unit 1 purchased by TEP3, and Salt River Project Agricultural Improvement and Power District, the owner of Springerville Unit 4, through participant billings recorded in September 2016;
a 7.04% return on original cost rate base of approximately $2 billion;
a cost of equity component of 9.75% and a cost of debt component of 4.32%;

a capital structure for rate making purposes of approximately 50% common equity and 50% long-term debt;
adoption of TEP's proposed depreciation and amortization rates, which include a reduction in the depreciable life for San Juan Unit 1; and
approval of a request to apply excess depreciation reserves against the unrecovered NBV of San Juan Unit 2 and the coal handling facilities at Sundt due to early retirement.
The ACC deferred matters related to net metering and rate design for new DG customers to Phase 2, which is currently expected to be completed in the first quarter of 2018. See Phase 2 Proceedings below.
Distributed Generation
In 2016, the ACC held proceedings under the Value and Cost of Distributed Generation docket to examine the ACC’s net metering rules and determine the value that utilities should pay DG customers who deliver electricity from rooftop solar systems back to the grid. Prior to these proceedings, the ACC’s net metering rules allowed DG customers who over-produced electricity to carry-over or “bank” excess electricity at a value equal to the full retail rate per kWh. Banked kWh could then be used by customers to offset future energy usage that could not be met by their DG system.
In December 2016, the ACC approved an order that will begin to reform net metering in Arizona. The order adopts a number of net metering changes and policies, including:
placing DG customers in a separate rate class;
grandfathering current DG customers under net metering rules and rate design for 20 years from interconnection application;
eliminating the banking of excess kWh for non-grandfathered DG customers;
compensating non-grandfathered customers for their exported kWh for 10 years at the DG export rate in effect at the time of interconnection;
updating the DG export rate annually; and
developing an avoided cost methodology for calculating the DG export rate in the utility’s next rate case.
The initial DG export rate will be established in Phase 2. See Phase 2 Proceedings below.
Phase 2 Proceedings
In March 2017, TEP filed direct testimony in its Phase 2 proceedings addressing rate design for new DG customers. The proposals include options for either a Time-Of-Use (TOU) energy rate with a basic customer service charge plus a monthly grid access fee based on the size of the DG system; or a TOU energy rate with a basic customer service charge plus a charge based on the highest hourly demand during the month. Consistent with the ACC’s decision in the Value of DG docket proceedings, TEP also proposed that: (i) new DG customers receive a bill credit for excess energy exported to the grid at an initial rate of 9.7 cents/kWh; (ii) the DG export rate be updated based on a five-year rolling average cost of the company’s owned and contracted utility scale renewable energy projects; (iii) customers who submit DG applications prior to the ACC’s Phase 2 decision be grandfathered under current net metering rules and rate design for a period of 20 years from the date of interconnection of their DG system; and (iv) customers who install DG after the ACC’s Phase 2 decision be compensated for 10 years at the rate in effect at the time they file an application for interconnection. A final ACC decision is currently expected in the first quarter of 2018. TEP cannot predict the outcome of these proceedings.
Generating Resources
As of September 30, 2017, approximately 52% of TEP's peak generation capacity is sourced from coal-fired generation resources. As part of TEP's long-term diversification strategy, TEP is evaluating additional steps to reduce its reliance on coal-fired generation.
Integrated Resource Plan
TEP’s long-term strategy to shift to a more diverse, sustainable energy portfolio is described in its Integrated Resource Plan (IRP) filed in April 2017 with the ACC. TEP's 2017 IRP discusses continuing efforts to diversify its generation portfolio including expanding renewable energy and natural gas-fired resources while reducing reliance on coal-fired generating

resources. TEP's existing coal generation fleet faces a number of uncertainties impacting the viability of continued operations including competition from other resources, fuel supply and land lease contract extensions, environmental regulations, and for jointly owned facilities, the willingness of other owners to continue their participation. Given this uncertainty, TEP may consider options that include changes in generation facility ownership shares, unit shutdowns, or the sale of generation assets to third-parties. TEP will seek regulatory recovery for amounts that would not otherwise be recovered, if any, as a result of these actions.
See Part I, Item 2. Liquidity and Capital Resources, Environmental Matters of this Form 10-Q for additional information regarding the impact of environmental matters on generation facility operations.
Navajo Generating Station
In June 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. We are currently recovering Navajo capital and operating costs in base rates using a useful life through 2030. As a result of the planned early retirement of Navajo, $52 million of the facility's NBV, and other related costs, were reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets in June 2017. We plan to seek recovery of all unrecovered costs in our next ACC rate case. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Sundt Generating Station
In August 2017, TEP submitted an Application to the PDEQ related to a generation modernization project at Sundt. In conjunction with the project, TEP will discontinue operation of Sundt Units 1 and 2 by the end of 2020. As a result of the planned early retirement, $32 million of the facilities' NBV was reclassified from Utility Plant, Net to Regulatory Assets on the Condensed Consolidated Balance Sheets. We plan to seek recovery of all unrecovered costs in our next ACC rate case. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Under the project outlined in the Application, TEP will invest in 10 RICE generators scheduled for commercial operation between June 2019 through March 2020. The RICE generators are capable of quick starts and fast ramps to balance the variability of intermittent renewable energy resources and will add 190 MW of nominal net generating capacity. The RICE generation will replace the 162 MW of nominal net generating capacity from Sundt Units 1 and 2, which are less efficient than the RICE generators and do not have the same quick start, fast ramp capabilities.
Gila River Generating Station
In October 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 (Tolling PPA). TEP’s obligations under the Tolling PPA are contingent upon SRP's acquisition of Gila River Units 1 and 2. In October 2017, SRP entered into a separate agreement with a third party to acquire Gila River Units 1 and 2 that is expected to be completed by early 2018 (Acquisition). If the Acquisition is terminated for any reason, either TEP or SRP may terminate the Tolling PPA without cost or penalty by providing written notice to the other party. The Tolling PPA provides TEP with an option to purchase Gila River Unit 2 during a three-year period beginning on the date the Acquisition is completed. TEP's purchase option price for Gila River Unit 2 is expected to be $165 million, but is dependent upon SRP's final purchase price. The Tolling PPA will replace coal-fired generation retirements and provide opportunities in the wholesale market for increased short-term wholesale revenues.
Long-Term Wholesale Sales
Navopache Electric Cooperative
In January 2017, a new long-term contract between TEP and Navopache Electric Cooperative (NEC) became effective. The contract expires at the end of 2041. TEP expects to serve 80% of NEC’s load requirements in 2017 and 100% beginning in 2018. In the nine months ended September 30, 2017, revenues from the NEC contract accounted for 8% of total WholesaleOperating Revenues on the Condensed Consolidated Statements of Income.
Interest RatesThe following discussion provides the significant items that affected our results of operations for the first three months of 2024 compared with the same period in 2023 presented on a pre-tax basis.
See Part II, Item 7A
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Operating Revenues
The following table provides a disaggregation of Operating Revenues:
Three Months Ended March 31,Increase (Decrease)
(in millions)20242023Percent
Operating Revenues
Retail$282 $233 21.0 %
Wholesale, Short-Term (1)
84 94 (10.6)%
Wholesale, Long-Term19 29 (34.5)%
Transmission14 17 (17.6)%
Springerville Units 3 and 4 Participant Billings36 27 33.3 %
Other18 36 (50.0)%
Total Operating Revenues$453 $436 3.9 %
(1)Includes revenue realized from wholesale trading as defined in the PPFAC plan of administration. We share 10% of any realized gains on trading transactions with retail customers through the PPFAC mechanism.
We reported Operating Revenues of $453 million for the first three months of 2024 compared with $436 million in the same period for 2023. The increase of $17 million, or 4%, was primarily due to:
•$49 million in higher retail revenue primarily due to: (i) higher PPFAC cost recoveries as a result of an increase in the PPFAC rate; and (ii) an increase in rates as approved in the 2023 Rate Order; partially offset by lower usage as a result of less favorable weather; and
•$9 million in higher participant billings primarily related to Springerville Unit 4.
The increase was partially offset by:
•$18 million in lower other revenue primarily due to the expiration of an asset management agreement and lower LFCR revenues;
•$10 million in lower short-term wholesale sales primarily due to a decrease in price; partially offset by an increase in volume and an increase in revenue realized from wholesale trading as defined in the PPFAC plan of administration; and
•$10 million in lower long-term wholesale sales primarily due to a decrease in volumes due to less favorable market conditions and the expiration of certain contracts.
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The following table provides key statistics impacting Operating Revenues:
Three Months Ended March 31,Increase (Decrease)
(kWh in millions)20242023Percent
Electric Sales (kWh) (1)
Retail Sales1,795 1,822 (1.5)%
Wholesale, Long-Term317 474 (33.1)%
Wholesale, Short-Term1,533 941 62.9 %
Total Electric Sales3,645 3,237 12.6 %
Average Revenue per kWh (2)
Retail15.71 12.78 22.9 %
Wholesale, Long-Term5.85 6.07 (3.6)%
Wholesale, Short-Term3.73 8.61 (56.7)%
Total Retail Customers (3)
449,619 444,834 1.1 %
(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, excluding revenue realized from wholesale trading as defined in the PPFAC plan of administration, 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 and 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
We reported Fuel and Purchased Power expense of $179 million for the first three months of 2024 compared with $185 million for the same period for 2023. The decrease of $6 million, or 3%, was primarily due to:
•$23 million in lower Fuel expense due to a decrease in natural gas prices; partially offset by an increase in coal prices and an increase in Gas-Fired Generation volumes; and
•$10 million in lower Purchased Power expense primarily due to a decrease in price.
The decrease was partially offset by a $25 million increase in PPFAC Recovery Treatment primarily due to an increase in PPFAC cost recoveries.
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The following table provides key statistics impacting Fuel and Purchased Power:
Three Months Ended March 31,Increase (Decrease)
(kWh in millions)20242023Percent
Sources of Energy
Coal-Fired Generation936 981 (4.6)%
Gas-Fired Generation1,892 1,582 19.6 %
Utility-Owned Renewable Generation198 230 (13.9)%
Total Generation3,026 2,793 8.3 %
Purchased Power, Non-Renewable403 179 125.1 %
Purchased Power, Renewable318 355 (10.4)%
Total Generation and Purchased Power (1)
3,747 3,327 12.6 %
(cents per kWh)
Average Fuel Cost of Generated Power (2)
Coal5.43 2.91 86.6 %
Natural Gas (3)
2.62 5.98 (56.2)%
Average Cost of Purchased Power (4)
Purchased Power, Non-Renewable1.36 9.20 (85.2)%
Purchased Power, Renewable6.75 6.45 4.7 %
(1)This number represents the kWh generated from our 2016 Annual Report on Form 10-Kgenerating stations including coal-fired, gas-fired, and Part II, Item 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 Total Generation (kWh) for each respective generation source. Management uses this metric to monitor rates and pricing as well as analyze the performance of generation facilities.
(3)Includes realized gains and losses from hedging activity.
(4)This metric represents 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
We reported Operations and Maintenance expense of $119 million for the first three months of 2024 compared with $108 million for the same period for 2023. The increase of $11 million, or 10%, was primarily due to:
•$8 million in higher reimbursable maintenance expenses related to Springerville Unit 4 primarily due to planned outages; partially offset by lower reimbursable maintenance expenses related to Springerville Unit 3; and
•$3 million in higher outside service expenses and operations and maintenance expenses at our generation facilities.
The increase was partially offset by $2 million in lower RES and DSM expenses.
Depreciation and Amortization Expense
We reported Depreciation and Amortization expense of this Form 10-Q$63 million for information regardingthe first three months of 2024 compared with $57 million for the same period for 2023. The increase of $6 million, or 11%, was primarily due to an increase in depreciation rates as approved in the 2023 Rate Order.
Other Income (Expense)
We reported Other Expense of $15 million for the first three months of 2024 compared with $16 million for the same period for 2023. The decrease of $1 million, or 6%, was primarily due to $3 million in higher AFUDC due to an increase in eligible
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construction expenditures; partially offset by $1 million in lower interest rate risks and its impact onincome primarily due to a reduction in under-recovered PPFAC costs.
Income Tax Expense
We reported Income Tax Expense of $7 million for the first three months of 2024 compared with $6 million for the same period for 2023. The increase of $1 million, or 17%, was primarily due to an increase in taxable earnings.



LIQUIDITY AND CAPITAL RESOURCES
Liquidity
Any extended period of economic disruption could affect our business, financial condition, and access to sources of liquidity. Cash flows may vary during the year with cash flows from operations typically being the lowest in the first quarter of the year and highest in the third quarter due to TEP’sour summer peaking load. As a resultWe face market risks associated with fluctuations in commodity prices, which can temporarily affect our cash flows prior to recovery through regulatory mechanisms. We cannot project the future level of the varied seasonal cash flow, we willcommodity prices or their volatility. We use as needed, our revolving credit facilityas needed to assist in fundingfund our business activities. We believe that we have sufficient liquidity under our revolving credit facilitythe 2021 Credit Agreement to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. The availability and terms under which TEP haswe have access to external financing dependsdepend on a variety of factors, including itsour credit ratings and conditions in the overallbank and capital markets.
Available Liquidity
(in millions)September 30, 2017
Cash and Cash Equivalents70
Amount Available under Revolving Credit Facility (1)
250
Total Liquidity$320
(in millions)March 31, 2024
Cash and Cash Equivalents$57 
Amount Available under Revolving Credit Agreement (1)
TEP's revolving credit facility provides for $250 million of revolving credit commitments with a LOC sublimit of $50 million with an original maturity date of October 2020. In October 2017, TEP requested and was granted its second one-year extension option. The facility's new maturity date is October 2022.250 
Total Liquidity$307 
(1)The 2021 Credit Agreement provides for $250 million of revolving credit commitments with swingline and LOC sublimits of $15 million and $50 million, respectively, and a maturity date of October 2026. See Access to Credit below.
Future Liquidity Requirements
We expect to meet all of our short-term and long-term financial obligations and other anticipated cash outflows for the foreseeable future. These obligations and anticipated cash outflows include but are not limited to,to: (i) dividend payments,payments; (ii) debt maturities, maturities; (iii) employee benefit obligations;and (iv) known commitments and other contractual obligations included in the Contractual Obligations including forecasted capital expenditures.
See Part I, Item 3. Quantitative and forecasted Capital Expenditures tables reported inQualitative Disclosures about Market Risk of this Form 10-Q for additional information regarding our 2016 Annual Report on Form 10-K and the material changes summarized below in the respective sections.market risks.
Summary of Cash Flows
The table below presents net cash provided by (used for) operating, investing, and financing activities:
 Nine Months Ended September 30, Increase (Decrease)
(in millions)2017 2016 Percent
Operating Activities337
 341
 (1.2)%
Investing Activities(254) (302) (15.9)%
Financing Activities(49) (38) 28.9 %
Net Increase in Cash and Cash Equivalents34
 1
 *
Cash and Cash Equivalents, Beginning of Period36
 56
 (35.7)%
Cash and Cash Equivalents, End of Period$70
 $57
 22.8 %
* Not meaningful
Three Months Ended March 31,Increase (Decrease)
(in millions)20242023Percent
Operating Activities$190 $121 57.0 %
Investing Activities(144)(129)11.6 %
Financing Activities— 135 (100.0)%
Net Increase (Decrease)46 127 (63.8)%
Beginning of Period43 51 (15.7)%
End of Period$89 $178 (50.0)%
Operating Activities
InNet cash flows provided by operating activities increased by $69 million in the first ninethree months of 2017, net cash flows from operating activities decreased by $4 million2024 compared with the same period in 2016.2023. The decrease isincrease was primarily due to: (i) higher PPFAC cost recoveries as a result of an ACC approved increase in the
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PPFAC credit that began returning the over-collected PPFAC balance to customers in February 2017;rate; (ii) $12.5 million received in September 2016higher retail revenues related to a settlement for operating costs related to Springerville Unit 1 not occurring in 2017; and (iii) changes in working capital related to the timing of billing collections and payments. The decrease was partially offset by $8 million in cash proceeds received in January 2017 from a settlement agreement and higher net income due to an increase in: (i)in rates as approved in the 20172023 Rate Order; and (ii) residential usage due to(iii) favorable weather. See Note 6 of Notes to Condensed Consolidated Financial Statementschanges in Part I, Item 1 of this Form 10-Q, FERC Matters and Claims Related to Springerville Generating Station Unit 1, respectively, for additional information.

working capital associated with wholesale sales.
Investing Activities
In the first nine months of 2017, netNet cash flows used for investing activities decreasedincreased by $48$15 million in the first three months of 2024 compared with the same period in 20162023 primarily due to a $57 million decreasean increase in cash paid for capital expenditures, highlighted by the September 2016 purchase of an undivided interest in Springerville Unit 1. The decrease was partially offset by an increase in renewable energy credits purchased in 2017.expenditures.
Financing Activities
InNet cash flows provided by financing activities decreased by $135 million in the first ninethree months of 2017, net cash flows used for financing activities increased by $11 million2024 compared with the same period in 20162023 primarily due to an increasea decrease in the dividend paid to UNS Energy in 2017.proceeds from long-term debt, net of 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 September 30, 2017, TEP'sMarch 31, 2024, our short-term investments included highly-ratedwere deposited in insured cash sweep and liquid money market funds.accounts.
Access to Revolving Credit Facility
We have access to working capital through a revolvingour credit agreement with lenders. TEP expects that amountsAmounts borrowed underfrom the credit agreement will be2021 Credit Agreement are used for working capital and other general corporate purposes and thatpurposes. LOCs will be issued from time to time to support energy procurement, hedging transactions, and hedging transactions. As of September 30, 2017, there was $250 million available under the revolving credit commitments and LOC facility. As of November 2, 2017, TEP had $250 million available under its revolving credit commitments and LOC facility.other business activities.
For details of TEP's credit facility seeSee Note 67 of Notes to Consolidated Financial Statements in Part II, Item 8 in our 20162023 Annual Report on Form 10-K. for additional information regarding our 2021 Credit Agreement.
Debt Financing
We use debt financing to meet a portion of our capital needs and lower our overall cost of capital. We are exposed to adverse changes in interest rates to the extent that we rely on variable rate financing. Our cost of capital is also affected by our credit ratings.
In 2016,December 2020, the ACC issued an order granting TEPour financing authority.authority that took effect January 1, 2021. The order extends and expands the previous financingprovides authority by:through December 2025 for: (i) extending authority from December 2016 to December 2020; (ii) increasing the outstandinga maximum amount of long-term debt limitation from $1.7 billionoutstanding not to $2.2exceed $2.9 billion; (iii) allowing(ii) parent equity contributions of up to $400$700 million; and (iv) continuing(iii) credit facilities not to exceed $300 million in the interest rate hedging authority.aggregate. In May 2022, we filed with the SEC an automatic shelf registration statement on Form S-3 which expires in May 2025.
We have, no plans to raise additional capital in 2017. TEP has, from time to time, refinanced or repurchased portions of itsour outstanding debt before scheduled maturity. In January 2015, TEP purchased $130 million aggregate principal amount of unsecured tax-exempt Industrial Development Revenue Bonds issued in June 2008 by the Industrial Development Authority of Pima County, Arizona for the benefit of TEP and the bonds were not remarketed. The multi-modal bonds had an original maturity date of September 2029. In September 2017 the bonds were retired.
Depending on market conditions, TEPwe may refinance otheror repurchase additional outstanding debt issuances or make additionalbefore its scheduled maturity.

As of March 31, 2024, we had $300 million of long-term debt repurchasesmaturing on March 15, 2025 recorded in Current Maturities of Long-Term Debt, Net on the Condensed Consolidated Balance Sheets. We anticipate issuing long-term debt in the future.third quarter of 2024.
Credit Ratings
Credit ratings affect our access to capital markets and supplemental bank financing. In April 2017,As of March 31, 2024, credit ratings from S&P Global Ratings upgraded TEP’s credit rating onand Moody’s Investors Service for our senior unsecured debt towere A- from BBB+(negative) and A3 (stable), and as of September 30, 2017 the credit rating remained unchanged. As of September 30, 2017, Moody’s Investors Servicerespectively.
Our credit ratings for TEP’s senior unsecured debt remained unchanged at A3.
TEP's 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 TEPour securities. Each rating should be evaluated independently of any other ratings.

Debt Covenants
Certain of TEP's debt agreements containThe 2021 Credit Agreement contains pricing based on TEP’sour credit ratings. A change in TEP’sour credit ratings can cause an increase or decrease in the amount of interest TEP payswe pay on itsour borrowings and the amount of fees it payswe pay for its LOCs and unused commitments. Also, under
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Debt Covenants
Under certain agreements, should TEPwe fail to maintain compliance with covenants, lenders could accelerate the maturity of all amounts outstanding. As of September 30, 2017, TEP wasMarch 31, 2024, we were 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.
Contributions from Parent
We received no equity contributions from UNS Energy in the first three months of 2024 and received an equity contribution of $6 million in the first three months of 2023.
Dividends Declared and Paid to Parent
We did not declare or pay dividends to UNS Energy in the first three months of 2024 or 2023.
Master Trading Agreements
TEP conducts itsWe conduct our wholesale marketing and risk management activities under certain master trading agreements. Under these agreements, TEPwe may be required to post credit enhancements in the form of cash or an LOCLOCs due to exposures exceeding unsecured credit limits provided to TEP,established for us 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 September 30, 2017, TEPMarch 31, 2024, we had posted no cash posted as collateral to provide credit enhancement related to our wholesale marketing or LOCs as credit enhancements with its counterparties.
Contribution from Parent
TEP received no equity contributions in the three and nine months ended September 30, 2017 or 2016.
Dividends Paid to Parent
TEP declared and paid a $35 million dividend to UNS Energy in the three and nine months ended September 30, 2017, and a $20 million dividend to UNS Energy in the three and nine months ended September 30, 2016.risk management activities.
Capital Expenditures
TEP'sOur routine capital expenditures include funds used for customer growth, system reinforcement, replacements and betterments, and costs to comply with environmental rules and regulations. Our capital expenditures inIn the first ninethree months of 20172024, there were $216 million comparedno material changes to $273 million for the same period in 2016. TEP'sour forecasted capital expenditures are summarized below:
(in millions)2017 2018 2019 2020 2021
Generation Facilities:         
Environmental Compliance$23
 $11
 $1
 $2
 $—
Renewable Energy6
 15
 21
 26
 26
Springerville Common Lease Purchase38
 —
 —
 —
 9
Replacement Generation Capacity (1)
13
 132
 190
 53
 29
Other Generation Facilities41
 80
 35
 76
 63
Total Generation Facilities121
 238
 247
 157
 127
Transmission and Distribution167
 176
 161
 169
 162
General and Other (2)
76
 76
 106
 53
 39
Total Capital Expenditures$364
 $490
 $514
 $379
 $328
(1)
Investments that will provide replacement capacity for the planned early retirements of generating resources which include: (i) RICE generators at Sundt; and (ii) the purchase option price for Gila River Unit 2. See Part I, Item 2. Factors Affecting Results, Generating Resources of this Form 10-Q for additional information on these projects.
(2)
Includes cost for information technology, fleet, facilities, and communication equipment.
These estimates are subject to continuing review and adjustment. Actual capital expenditures may differ from these estimates due to fluctuations in business and market conditions, construction schedules, possible early plant closures, changes in generation resources, environmental requirements, state or federal regulations, and other factors. We expect to pay for forecasted capital expenditures with internally generated funds and external financings, which may include issuances of long-term debt or other borrowings.

Contractual Obligations
In the first nine months of 2017, there have been no material changes outside the ordinary course of business to contractual obligations as reported in our 20162023 Annual Report on Form 10-K.
Off-Balance Sheet Arrangements
Other than the unrecorded contractual obligations reported on the contractual obligations table presented in our 2016 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
Prior yearUnder the terms of the tax legislation includes provisions that make qualified property placedsharing agreement with UNS Energy, we made $3 million in service between 2010 and 2019 eligibletax sharing payments for bonus depreciation for tax purposes. In addition, the IRS issued guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions are an acceleration of tax benefits TEP otherwise would have received over 20 years and have created net operating loss carryforwards that can be used to offset future taxable income. As a result, TEP did not pay any federal or state income taxes in the first ninethree months of 20172024 and doesreceived $6 million in tax sharing payments for the first three months of 2023. Future cash flows are subject to change and are not expectexpected to make any payments until 2020.have a significant impact on our operating cash flows.
Environmental Matters
The Environmental Protection Agency (EPA) regulateshas the authority to regulate the amount of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), particulate matter, mercury and other by-products produced by generation facilities. TEPWe may incur additional costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at itsour 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, TEP iswe are unable to predict the impact of the changing laws and regulationsthey may have on itsour operations and consolidated financial results. Complying with these changes may reduce operating efficiency. TEP expects to recoverefficiency and increase capital and operating costs. We expect recovery of the costcosts of environmental compliance through cost recovery mechanisms and Retail Rates.
Regional Haze RulesRegulations
The EPA's Regional Haze Rules requirerule requires emission controls known as Best Available Retrofit Technology (BART) forreductions from certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas.areas (Regional Haze). The rule calls for all states to establish goals and emission reduction strategies for improving visibility.visibility in these areas. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on land leased from the Navajo Nation, they are not subject to state oversight; the EPA oversees regional haze planning for these generation facilities.
In the western United States, Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install Selective Catalytic Reduction (SCR). The BART provisions do not apply to Springerville Units 1 and 2 since they were constructedapproval in the 1980s, afterform of a SIP and must review and submit revisions to the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reductions are not likely to impact Springerville operations until after 2021. SIP on a periodic basis.
In December 2016, the EPA signed a final rule entitled "Protection of Visibility: Amendments to Requirements for State Plans." Amongthat, among other things, changed the rule changes thesubmittal date for submittal of the next regional haze implementation planRegional Haze SIP revisions from 2018 to 2021. BasedThe Arizona Department of Environmental Quality (ADEQ) began to develop a control strategy with a focus on recent Regional Haze requirement time-frames, TEP anticipatesmaking reasonable progress toward the national visibility goal. In July 2019, we were notified by ADEQ that impacts, if any, toSundt Unit 3 and Springerville will likely occur three to five years after the 2021 plan submittal date. TEP cannot predict the ultimate outcome of these matters.
Four Corners
In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy. As a result, APS closed Units 1, 2, and 3 in December 2013 and agreed to install SCR on Units 4 and 5. TEP owns 7% of Four Corners Units 4 and 5. TEP's estimated share of NOx emissions control costs to comply with the rules is $44 million in capital expenditures and $2 million in annual operations and maintenance expenses. The SCR projects are scheduled to be completed by July 2018.
Navajo
In August 2014, the EPA published a final Federal Implementation Plan (FIP) which provides that one unit at Navajo will be shut down by 2020, SCR, or the equivalent, will be installed on the remaining two units by 2030, and conventional coal-fired generation will cease by December 2044. The final BART rule includes options that accommodate potential ownership changes at the facility. The facility has until December 2019 to notify the EPA of how it will comply with the FIP.

In June 2017, the Navajo Nation approved a land lease extension which allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. As a result of the early retirement of Navajo, TEP and the co-owners will no longer be responsible for implementing the FIP. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the early retirement of Navajo.
San Juan
In October 2014, the EPA published a final rule approving a revised SIP covering BART requirements for San Juan, which includes the closure of Units 2 and 3 by the end of December 2017 and the installation of Selective Non-Catalytic Reduction (SNCR) on Units 1 and 4. TEP owns 50% of Units 1 and 2 at San Juan. Public Service Company of New Mexico (PNM),had been selected for potential emissions controls evaluation.
We conducted the operator of San Juan, completedpotential emissions controls evaluation, commonly referred to as the installation of SNCRfour factor analysis, for the three units. These evaluations were submitted to the ADEQ in February 2016. PNM obtained New Mexico Public Regulation Commission approval to shut down Units 2March 2020 and 3 at San Juan.
In anticipation ofcompliance measures for the retirement of San Juan Unit 2 in December 2017, TEP applied excess depreciation reserves against the unrecovered NBV as approvedthree units were included in the 2017 Rate Order. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information relatedrevised SIP. In August 2022, the ADEQ submitted the revised SIP to the retirement of San Juan Unit 2.
Sundt
In June 2014,EPA, and the EPA issued a letter to the ADEQ
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finding Arizona's SIP revision complies with the completeness criteria outlined in the rule. The EPA must take final ruleaction on Arizona's Regional Haze SIP Revision by March 30, 2025, per consent decree entered in the U.S. District Court for the District of Columbia. We anticipate that required TEP to either: (i) install, by mid-2017, SNCR and dry sorbent injectioncompliance strategies, if Sundt Unit 4 continued to use coal as a fuel source; or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. Under the rule, TEP wasany, will likely be required to notifybe implemented one year following EPA approval of ADEQ's revised SIP. We cannot predict the EPAoutcome of its decision by March 2017.
In March 2016, TEP notified the EPA of its decisionthis matter but will continue to permanently eliminate coal as a fuel source to complywork with the better-than-BART alternative emission limits. TEP applied excess depreciation reserves against the unrecovered NBV of the coal handling facilities at SundtADEQ to determine compliance strategies as approved in the 2017 Rate Order. See Note 1 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for additional information related to the retirement of the coal handling facilities at Sundt.needed.
Greenhouse Gas Regulation
In August 2015, the EPA issued the CPPClean Power Plan (CPP) limiting CO2 emissions from existing and new fossil fueledfuel-based generation facilities. The Clean Power Plan (CPP) establishesCPP established state-level CO2 emission rates and mass-based goals that applyapplied to fossil fuel-firedfuel-based generation. The plan targets CO2 emissions reductions
In June 2019, the EPA repealed the CPP and issued the Affordable Clean Energy (ACE) rule, establishing new emission guidelines for existing facilities by 2030 and establishes interim goals that begin in 2022. States were required to develop and submit a final compliance plan, or an initial plan with an extension request, to the EPA by September 2016. States that received an extension are required to submit a final completed plan to the EPA by September 2018.
The EPA incorporated the compliance obligations for existingcoal-fired generation facilities located in Indian Country, like the Navajo Nation, in the existing sources rule and a newly proposed Federal Plan using a compliance method similar to that of the states. The proposed Federal Plan would be implemented for any Indian nation and/or state that does not submit a plan or that does not have an EPA or state approved plan. TEP will work with the participants at Four Corners and Navajo to determine how this revision may impact compliance and operations at both facilities. TEP has submitted commentsbased on the proposed Federal Plan impacting ourBest System of Emission Reduction (BSER) for GHG emissions. The BSER for GHG emissions from existing coal-fired generation facilities including Four Corners and Navajo, stating, among other things,is defined as Heat-Rate Improvements that can be applied at the EPA should not regulatesource. The states would then use these emission guidelines to establish state performance standards, considering source specific factors such as the greenhouse gases on the Navajo Nation because it is not appropriate or necessary. The reductionremaining useful life of greenhouse gases achieved due to the shutdowns resulting from compliance with the Regional Haze Rules will be equivalent to those required under the CPP rule.
TEP's compliance requirements under the CPP are subject to the outcomes of potential proceedings and litigation challenging the rule. In February 2016, the U.S. Supreme Court granted a stay effectively ordering the EPA to stop CPP implementation efforts until legal challenges to the regulation have been resolved.an individual unit.
In September 2016,January 2021, the U.S. Court of Appeals for the DistrictD.C. Circuit: (i) vacated the EPA's repeal of Columbia Circuit (U.S. Court of Appeals) heard oral arguments on the CPP. On March 28, 2017, the Department of Justice filed a motion to hold the lawsuits relatedCPP and remanded it back to the EPA for further consideration (the vacatur was later stayed by the court); and (ii) vacated and remanded the ACE rule. Certain petitioners, defending the repeal of the CPP, filed petitions for an order requesting that the U.S. Supreme Court review the decision of the lower court. The U.S. Supreme Court granted the petitions, consolidated the cases, and in abeyance. June 2022, reversed the D.C. Circuit and remanded the cases back for further proceedings.
On April 28, 2017,25, 2024, the U.S. Court of Appeals granted that motionEPA released a final rule repealing the ACE rule and delayed for 60 days the litigation overaddressing GHG emissions from existing steam electric generating units and new combustion turbines. We are analyzing the EPA's CPP for existing and new generation facilities. The EPA has asked for an extension.
In March 2017, a Presidential Executive Order (EO) titled "Promoting Energy Independence and Economic Growth" was issued. The EO instructs the EPA to review the final greenhouse gas rule for existing and new and modified generation facilities and either suspend, revise, or rescind the rule as appropriate. In April 2017, the EPA announced in the Federal Register that it is reviewing and, if appropriate, will initiate proceedings to suspend, revise, or rescind the CPP rule.

In October 2017, the EPA signed a proposal to repeal the CPP that was promulgated on October 23, 2015. Specifically, the EPA proposes a change in the legal interpretation as applied to section 111(d) of the Clean Air Act (CAA) on which the CPP was based. Comments to this proposal will be accepted for 60 days following publication in the Federal Register.
The EPA has not determined whether or not it will issue a potential replacement rule and if it will do so, under what form. The EPA intends to issue an Advance Notice of Proposed Rulemaking (ANPRM) in the near future to seek comment on what, if any, regulation should replace the existing CPP. In light of recent events TEP cannot predict the final outcome of these matters.this matter at this time.
Coal Combustion Residuals Regulation
In April 2015, the EPA issued apublished final rule requiring all coal ashrules effective October 2015, which established technical requirements for CCR landfills and other coal combustion residuals to be treated as a solid wastesurface impoundments under Subtitlesubtitle D of the Resource Conservation and Recovery Act (RCRA Subtitle D) for disposal in landfills and/or surface impoundments while allowingAct. The CCR rules provide for the continued recyclingsafe disposal of coal ash. TEP does not operate any impoundments. Under the rule,ash from coal-fired generation facilities, including among other things, inspection, monitoring, recordkeeping, and reporting requirements. We currently dispose of CCR in an ash landfill located at the Springerville Generating Station. Arizona Public Service Company, the operator of Four Corners, currently disposes of CCR in ash landfill is classified as an existing landfillponds and isdry storage areas located at the facility. At this time, we do not subject to the lateral expansion requirements. However, TEP will incur additional costs for site preparation and monitoring at Springerville to be fully compliant with the rule. TEP’santicipate our share of costs at Springerville is estimatedthe cost to be $2 million,complete any corrective actions to close the majority of which is expectedCCR disposal units, or to be capital expenditures. TEP currently estimates its share of costs to be $5 milliongather and perform remedial evaluations on groundwater at Four Corners $3 million at Navajo,Units 4 and less than $1 million at San Juan,5, will have a significant impact on our financial position, results of operations, or cash flows.
In May 2023, the majorityEPA published a proposed Legacy CCR Surface Impoundments Rule that expands the scope of federal CCR regulations to address the impacts from historical CCR disposal activities that would have ceased prior to 2015. The EPA proposes to establish two new categories of federally regulated CCR: (i) legacy surface impoundments, which are expected to be capital expenditures.inactive surface impoundments at inactive facilities that no longer receive CCR but contained both CCR and liquids on or after October 19, 2015; and (ii) CCR management units which broadly encompass any location at an operating coal-fired generation facility where CCR would have been placed on land. As proposed, a CCR management unit would include not only historically closed landfills and surface impoundments, but also prior applications of CCR on land such as for structural fill. On April 25, 2024, the EPA released the final rule which establishes assessment, monitoring, closure, and post-closure requirements for legacy CCR impoundments and CCR management units. We are analyzing the EPA's final rule and cannot predict the outcome of this matter at this time.
Good Neighbor Federal Implementation Plan
In December 2016, Congress approvedSeptember 2018, the Water Infrastructure ImprovementsADEQ submitted to the EPA the Arizona State Implementation Plan Revision to address the interstate transport of ozone (Arizona Ozone Transport SIP Revision) under the 2015 ozone National Ambient Air Quality Standard (NAAQS). In June 2022, the EPA proposed to approve the Arizona Ozone Transport SIP Revision, finding that it contained adequate provisions to prohibit emissions that will significantly contribute to nonattainment or interference with maintenance of the 2015 ozone NAAQS in other states.
In March 2023, the EPA released its final Federal Implementation Plan (FIP) to address the interstate transport of ozone (Good Neighbor FIP). The Good Neighbor FIP was published in the Federal Register in June 2023, with an effective date of August 4, 2023. The Good Neighbor FIP establishes requirements for those states where the EPA disapproved Ozone Transport SIP
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Revisions in whole or part. The Good Neighbor FIP requires NOx emission reductions from fossil-fueled generation facilities. The EPA provided an updated analysis in the Good Neighbor FIP that suggested Arizona may be significantly contributing to one or more nonattainment or maintenance receptors and that a separate action for Arizona was forthcoming.
In February 2024, the EPA published a proposed supplemental Good Neighbor rulemaking proposing to partially approve and partially disapprove the Arizona Ozone Transport SIP Revision and to expand the coverage of the Good Neighbor FIP to include Arizona. Arizona’s inclusion under the Good Neighbor FIP would subject certain of our fossil-fueled generation facilities to NOx emission reduction requirements. The EPA must take final action on Arizona’s Ozone Transport SIP Revision by August 30, 2024, per consent decree entered in the U.S. District Court for the Nation Act which authorizes the States to establish permit programs under RCRA Subtitle D for implementing regulation for Coal Combustion Residuals (CCR). Northern District of California. The public comment period is currently open and closes May 16, 2024.
TEP is currently workinganalyzing the EPA’s proposal. We cannot predict the outcome of these matters at this time but will continue to advocate for reasonable regulation and maintain communication with other affected utilities and the Arizona Department of Environmental Quality to explore the possibility of developing a State administered program to enforce CCR regulation.ADEQ.



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 reported amounts of assets and liabilities net revenuesreported in the financial statements and expenses, and disclosure of contingent liabilities.related notes. Management believes that there have been no significant changes during the ninethree months ended September 30, 2017,March 31, 2024, 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 20162023 Annual Report on Form 10-K.


NEW ACCOUNTING PRONOUNCEMENTSSTANDARDS ISSUED AND NOT YET ADOPTED
For a discussion of new accounting pronouncements affecting TEP, see Note 101 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. WeTEP can enter into interest rate swaps and financing transactions to manage changes in interest rates. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows but are not expected to affect earnings due to expected recovery through regulatory mechanisms.
There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A in our 20162023 Annual Report on Form 10-K.


ITEM 4. CONTROLS AND PROCEDURES
TEP’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer) supervised and participated in TEP’s evaluation of its disclosure controls and procedures as such term is defined under Rule 13(a) – 13a–15(e) orand Rule 15(d) – 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 SEC’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 arewere effective as of September 30, 2017.
While TEP continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting, there has beenMarch 31, 2024. There was no change in TEP’s internal control over financial reporting during
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the quarter ended September 30, 2017,March 31, 2024, that has materially affected, or is reasonably likely to materially affect, TEP’s internal control over financial reporting.

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PART II
ITEM 1. LEGAL PROCEEDINGS
For a description of certain legal proceedings affecting TEP, refer to Note 6 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Pursuant to Item 103 of Regulation S-K under the Exchange Act, TEP is required to disclose certain information about environmental proceedings to which a governmental authority is a party if TEP reasonably believes such proceedings may result in monetary sanctions, exclusive of interest and costs, above a stated threshold. TEP has elected to apply a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required.

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 20162023 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 20162023 Annual Report on Form 10-K.

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ITEM 5. OTHER INFORMATION

RATIO OF EARNINGS TO FIXED CHARGES
 Nine Months Ended Twelve Months Ended
 September 30, 2017 September 30, 2017
Ratio of Earnings to Fixed Charges5.74
 4.89
For purposes of this computation, earnings are defined as pre-tax earnings from continuing operations before minority interest, or income/loss from equity method investments, plus interest expense and amortization of debt discount and expense related to indebtedness. Fixed charges are interest expense, including amortization of debt discount and expense, interest on operating lease payments, and expense on indebtedness, including capital lease obligations.


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ITEM 6. EXHIBITS
EXHIBIT INDEX
Exhibit No.Description
EXHIBIT INDEX
Exhibit No.Description
Computation of Ratio of Earnings to Fixed Charges
31(a)
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by David G. HutchensSusan M. Gray
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, by Frank P. Marino
***32
Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)
101.INSXBRL 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.SCHXBRL Taxonomy Extension Schema Document
101.CALXBRL Taxonomy Extension Calculation Linkbase Document
101.LABXBRL Taxonomy Extension Label Linkbase Document
101.PREXBRL Taxonomy Extension Presentation Linkbase Document
101.DEFXBRL Taxonomy Extension Definition Linkbase Document
104The cover page from TEP's Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, formatted in Inline XBRL and contained in Exhibit 101
*Filed herewith.
**
*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:November 3, 2017April 30, 2024/s/ Frank P. Marino
Frank P. Marino
Sr. Vice President, and Chief Financial Officer, and Director
(Principal Financial Officer)




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