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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Restricted CashRestricted 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) | 2024 | | 2023 |
Cash and Cash Equivalents | $ | 57 | | | $ | 144 | |
Restricted Cash included in: | | | |
Investments and Other Property | 22 | | | 21 |
Current Assets—Other | 10 | | | 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.
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) | | | | | 2024 | | 2023 |
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: |
| | | |
Period | | Cents per kWh |
March 2017 through March 2018 | | (0.20 | ) |
May 2016 through February 2017 | | 0.15 |
|
April 2015 through April 2016 | | 0.68 |
|
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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2024 | | December 31, 2023 |
Regulatory Assets | | | | | |
Pension and Other Postretirement Benefits (Note 7) | Various | | $ | 106 | | | $ | 107 | |
Early Generation Retirement Costs | Various | | 47 | | | 48 | |
Derivatives (Note 8) | 6 | | 40 | | | 26 | |
Lost Fixed Cost Recovery | 1 | | 33 | | | 35 | |
Property Tax Deferrals (1) | 1 | | 30 | | | 30 | |
Final Mine Reclamation and Retiree Healthcare Costs (2) | 16 | | 21 | | | 6 | |
Under-Recovered Purchased Energy Costs | 1 | | 7 | | | 55 | |
Income Taxes Recoverable through Future Rates (3) | Various | | 6 | | | 6 | |
Unamortized Loss on Reacquired Debt | Various | | 5 | | | 5 | |
| | | | | |
| | | | | |
Other Regulatory Assets | Various | | 14 | | | 12 | |
Total Regulatory Assets | | | 309 | | | 330 | |
Less Current Portion | 1 | | 113 | | | 147 | |
Total Noncurrent Regulatory Assets | | | $ | 196 | | | $ | 183 | |
| | | | | | | | | | | | | | | | | |
Regulatory Liabilities | | | | | |
Income Taxes Payable through Future Rates (3) | Various | | $ | 225 | | | $ | 229 | |
Net Cost of Removal (4) | Various | | 132 | | | 130 | |
Renewable Energy Standard | Various | | 76 | | | 77 | |
Derivatives (Note 8) | 6 | | 28 | | | 28 | |
Demand Side Management | 1 | | 10 | | | 9 | |
Deferred Investment Tax Credits | Various | | 6 | | | 6 | |
Pension and Other Postretirement Benefits (Note 7) | Various | | 4 | | | 4 | |
Transmission Revenue Requirement Balancing Account | 1 | | 2 | | | 5 | |
| | | | | |
| | | | | |
| | | | | |
Other Regulatory Liabilities | Various | | — | | | 1 | |
| | | | | |
| | | | | |
| | | | | |
Total Regulatory Liabilities | | | 483 | | | 489 | |
Less Current Portion | 1 | | 92 | | | 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.
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 Rates | Various | | 31 |
| | 29 |
|
Lost Fixed Cost Recovery | 1 | | 29 |
| | 23 |
|
Property Tax Deferrals | 1 | | 24 |
| | 23 |
|
Springerville Unit 1 Leasehold Improvements (3) | 6 | | 14 |
| | 17 |
|
Sundt Coal Handling Facilities (4) | N/A | | — |
| | 14 |
|
Other Regulatory Assets | Various | | 29 |
| | 20 |
|
Total Regulatory Assets | | | 367 |
| | 281 |
|
Less Current Portion | 1 | | 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 Standard | Various | | 43 |
| | 32 |
|
Purchased Power and Fuel Adjustment Clause | 1 | | 20 |
| | 38 |
|
Deferred Investment Tax Credits | Various | | 20 |
| | 23 |
|
Other Regulatory Liabilities | Various | | 9 |
| | 14 |
|
Total Regulatory Liabilities | | | 272 |
| | 377 |
|
Less Current Portion | 1 | | 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) | | | | | 2024 | | 2023 |
Retail | | | | | $ | 282 | | | $ | 233 | |
Wholesale | | | | | 89 | | | 126 | |
Other Services | | | | | 39 | | | 31 | |
Revenues from Contracts with Customers | | | | | 410 | | | 390 | |
Alternative Revenues | | | | | 9 | | | 13 | |
Other | | | | | 34 | | | 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, 2024 | | December 31, 2023 |
Retail | $ | 89 | | | $ | 109 | |
Retail, Unbilled | 47 | | | 57 | |
Retail, Allowance for Credit Losses | (11) | | | (12) | |
Wholesale (1) | 29 | | | 37 | |
Due from Affiliates (Note 5) | 13 | | | 7 | |
Other | 26 | | | 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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
| | | | | | | |
(in millions) | September 30, 2017 | | December 31, 2016 |
Customer | $ | 118 |
| | $ | 74 |
|
Due from Affiliates (Note 4) | 7 |
| | 9 |
|
Unbilled | 49 |
| | 34 |
|
Other | 18 |
| | 13 |
|
Allowance for Doubtful Accounts | (6 | ) | | (5 | ) |
Accounts Receivable, Net | $ | 186 |
| | $ | 125 |
|
ALLOWANCE FOR CREDIT LOSSESTEP 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) | | | | | 2024 | | 2023 |
Beginning of Period | | | | | $ | (12) | | | $ | (9) | |
Credit Loss Expense | | | | | (1) | | | (1) | |
Write-offs | | | | | 2 | | | 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, 2024 | | December 31, 2023 |
Receivables from Related Parties | | | |
UNS Energy | $ | 6 | | | $ | — | |
UNS Electric | 5 | | | 5 | |
UNS Gas | 2 | | | 2 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
Total Due from Related Parties | $ | 13 | | | $ | 7 | |
| | | |
Payables to Related Parties | | | |
UNS Energy | $ | 5 | | | $ | 1 | |
UNS Electric | 1 | | | 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 Gas | 2 |
| | 2 |
|
Total Due from Related Parties | $ | 7 |
| | $ | 9 |
|
| | | |
Payables to Related Parties | | | |
SES | $ | 2 |
| | $ | 2 |
|
UNS Electric | 1 |
| | — |
|
Total Due to Related Parties | $ | 3 |
| | $ | 2 |
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents the components of related party transactions included in the Condensed Consolidated Statements of Income: | | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
(in millions) | | | | | 2024 | | 2023 |
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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(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
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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 Cost | 3 |
| | 4 |
| | 1 |
| | 1 |
|
Expected Return on Plan Assets | (6 | ) | | (5 | ) | | (1 | ) | | — |
|
Amortization of Net Loss | 2 |
| | 1 |
| | — |
| | — |
|
Net Periodic Benefit Cost | $ | 2 |
| | $ | 3 |
| | $ | 1 |
| | $ | 2 |
|
| | | Nine Months Ended September 30, |
| Pension Benefits | | | Pension Benefits | | Other Postretirement Benefits |
| Three Months Ended March 31, | | | Three Months Ended March 31, |
(in millions) | 2017 | | 2016 | | 2017 | | 2016 | (in millions) | 2024 | | 2023 | | 2024 | | 2023 |
Service Cost | $ | 9 |
| | $ | 9 |
| | $ | 3 |
| | $ | 3 |
|
Non-Service Cost (1) | |
Interest Cost | |
Interest Cost | |
Interest Cost | 11 |
| | 11 |
| | 2 |
| | 2 |
|
Expected Return on Plan Assets | (18 | ) | | (17 | ) | | (1 | ) | | (1 | ) |
Amortization of Net Loss | 6 |
| | 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.
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 Expenditures | 18 |
| | 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.
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 1 | | Level 2 | | | | Total |
(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 Assets | 40 | | | 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 Assets | 34 | | | 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 Assets | 67 |
| | — |
| | 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.
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 Assets | 30 |
| | 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 Sheets | | Gross Amount Not Offset in the Balance Sheets | | Net Amount |
| | Counterparty Netting of Energy Contracts | | Cash 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
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Level 2. TEP categorizes derivatives in Level 3 when an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers is used.
For both purchased power and natural gas prices, TEP obtains quotes from brokers, major market participants, exchanges, or industry publications and relies on its own price experience from active transactions in the market. The 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) | | | | | 2024 | | 2023 |
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.
|
| | | | | | | | | | | | | | | |
| 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 |
|
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) | | | | | 2024 | | 2023 |
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 GWh | 3,840 |
| | 2,610 |
|
Gas Contracts BBtu | 29,261 |
| | 12,355 |
|
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 Contracts | Market approach | | $ | 5 |
| | $ | (1 | ) | | Market price per MWh | | $ | 17.55 |
| | $ | 34.05 |
|
|
| | | | | | | | | | | | | | | | | | | |
(in millions) | December 31, 2016 |
Forward Power Contracts | Market 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 Instruments | 1 |
| | 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, 2024 | | December 31, 2023 |
Power Contracts GWh | 5,468 | | | 1,449 | |
Gas Contracts BBtu | 97,012 | | | 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.
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
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 Hierarchy | | Net Carrying Value | | Fair Value |
(in millions) | | March 31, 2024 | | December 31, 2023 | | March 31, 2024 | | December 31, 2023 |
Liabilities | | | | | | | | | |
Long-Term Debt, including Current Maturities | Level 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 Maturities | Level 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) | 2024 | | 2023 |
Accrued Capital Expenditures | $ | 47 | | | $ | 47 | |
Renewable Energy Credits | 5 | | | 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.
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
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.
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.
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) | | | | | | | |
Residential | 1,361 |
| | 1,344 |
| | 17 |
| | 1.3 | % |
Commercial | 653 |
| | 627 |
| | 26 |
| | 4.1 | % |
Industrial | 559 |
| | 590 |
| | (31 | ) | | (5.3 | )% |
Mining | 251 |
| | 245 |
| | 6 |
| | 2.4 | % |
Public Authorities | 3 |
| | 6 |
| | (3 | ) | | (50.0 | )% |
Total Retail Sales by Class | 2,827 |
| | 2,812 |
| | 15 |
| | 0.5 | % |
Retail Revenues (in millions) | | | | | | | |
Residential | $ | 119 |
| | $ | 101 |
| | $ | 18 |
| | 17.8 | % |
Commercial | 67 |
| | 60 |
| | 7 |
| | 11.7 | % |
Industrial | 31 |
| | 30 |
| | 1 |
| | 3.3 | % |
Mining | 11 |
| | 10 |
| | 1 |
| | 10.0 | % |
Public Authorities | — |
| | — |
| | — |
| | — | % |
Retail Margin Revenues by Class | 228 |
| | 201 |
| | 27 |
| | 13.4 | % |
LFCR Revenues | 6 |
| | 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 Revenues | 92 |
| | 98 |
| | (6 | ) | | (6.1 | )% |
DSM and RES Surcharge Revenues | 14 |
| | 15 |
| | (1 | ) | | (6.7 | )% |
Total Retail Revenues (GAAP) | $ | 340 |
| | $ | 320 |
| | $ | 20 |
| | 6.3 | % |
Average Retail Margin Rate by Class (cents/kWh) | | | | | | | |
Residential | 8.74 |
| | 7.51 |
| | 1.23 |
| | 16.4 | % |
Commercial | 10.26 |
| | 9.57 |
| | 0.69 |
| | 7.2 | % |
Industrial | 5.55 |
| | 5.08 |
| | 0.47 |
| | 9.3 | % |
Mining | 4.38 |
| | 4.08 |
| | 0.30 |
| | 7.4 | % |
Public Authorities (2) | 8.28 |
| | 5.76 |
| | 2.52 |
| | 43.8 | % |
Average Retail Margin Rate by Class | 8.07 |
| | 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 Rate | 3.25 |
| | 3.49 |
| | (0.24 | ) | | (6.9 | )% |
Average DSM and RES Surcharge Rate | 0.50 |
| | 0.53 |
| | (0.03 | ) | | (5.7 | )% |
Total Average Retail Rate | 12.03 |
| | 11.38 |
| | 0.65 |
| | 5.7 | % |
Weather Data | | | | | | | |
Cooling Degree Days | | | | | | | |
Actual | 1,006 |
| | 962 |
| | 44 |
| | 4.6 | % |
10-year Average | 1,018 |
| | 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) | | | | | | | |
Residential | 3,066 |
| | 2,990 |
| | 76 |
| | 2.5 | % |
Commercial | 1,671 |
| | 1,633 |
| | 38 |
| | 2.3 | % |
Industrial | 1,487 |
| | 1,537 |
| | (50 | ) | | (3.3 | )% |
Mining | 745 |
| | 743 |
| | 2 |
| | 0.3 | % |
Public Authorities | 13 |
| | 23 |
| | (10 | ) | | (43.5 | )% |
Total Retail Sales by Class | 6,982 |
| | 6,926 |
| | 56 |
| | 0.8 | % |
Retail Revenues (in millions) | | | | | | | |
Residential | $ | 268 |
| | $ | 226 |
| | $ | 42 |
| | 18.6 | % |
Commercial | 162 |
| | 146 |
| | 16 |
| | 11.0 | % |
Industrial | 80 |
| | 80 |
| | — |
| | — | % |
Mining | 29 |
| | 27 |
| | 2 |
| | 7.4 | % |
Public Authorities | 1 |
| | 1 |
| | — |
| | — | % |
Retail Margin Revenues by Class | 540 |
| | 480 |
| | 60 |
| | 12.5 | % |
LFCR Revenues | 17 |
| | 14 |
| | 3 |
| | 21.4 | % |
DSM Performance Bonus | 2 |
| | 2 |
| | — |
| | — | % |
Other Retail Margin Revenues | 2 |
| | 4 |
| | (2 | ) | | (50.0 | )% |
Retail Margin Revenues (non-GAAP) (1) | 561 |
| | 500 |
| | 61 |
| | 12.2 | % |
Fuel and Purchased Power Revenues | 219 |
| | 243 |
| | (24 | ) | | (9.9 | )% |
DSM and RES Surcharge Revenues | 40 |
| | 38 |
| | 2 |
| | 5.3 | % |
Total Retail Revenues (GAAP) | $ | 820 |
| | $ | 781 |
| | $ | 39 |
| | 5.0 | % |
Average Retail Margin Rate by Class (cents/kWh) | | | | | | | |
Residential | 8.74 |
| | 7.56 |
| | 1.18 |
| | 15.6 | % |
Commercial | 9.69 |
| | 8.94 |
| | 0.75 |
| | 8.4 | % |
Industrial | 5.38 |
| | 5.20 |
| | 0.18 |
| | 3.5 | % |
Mining | 3.89 |
| | 3.63 |
| | 0.26 |
| | 7.2 | % |
Public Authorities (2) | 7.56 |
| | 5.67 |
| | 1.89 |
| | 33.3 | % |
Average Retail Margin Rate by Class | 7.73 |
| | 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 Rate | 3.14 |
| | 3.51 |
| | (0.37 | ) | | (10.5 | )% |
Average DSM and RES Surcharge Rate | 0.57 |
| | 0.55 |
| | 0.02 |
| | 3.6 | % |
Total Average Retail Rate | 11.74 |
| | 11.28 |
| | 0.46 |
| | 4.1 | % |
Weather Data | | | | | | | |
Cooling Degree Days | | | | | | | |
Actual | 1,592 |
| | 1,431 |
| | 161 |
| | 11.3 | % |
10-year Average | 1,502 |
| | 1,491 |
| | * |
| | * |
|
Heating Degree Days | | | | | | | |
Actual | 614 |
| | 629 |
| | (15 | ) | | (2.4 | )% |
10-year Average | 739 |
| | 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 Wholesale | 25 |
| | 26 |
| | 73 |
| | 57 |
|
Transmission | 8 |
| | 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.
|
| | | | | | | | | | | | | | | |
| 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 |
|
Miscellaneous | 10 |
| | 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 Generation | 2,212 |
| | 2,369 |
| | $ | 56 |
| | $ | 53 |
|
Gas-Fired Generation | 1,073 |
| | 1,060 |
| | 34 |
| | 33 |
|
Utility Owned Renewable Generation | 21 |
| | 17 |
| | — |
| | — |
|
Reimbursed Fuel Expense, Springerville Units 3 and 4 (1) | — |
| | — |
| | 2 |
| | 1 |
|
Total Generation | 3,306 |
| | 3,446 |
| | 92 |
| | 87 |
|
Purchased Power, Non-Renewable | 587 |
| | 444 |
| | 29 |
| | 19 |
|
Purchased Power, Renewable | 158 |
| | 160 |
| | 10 |
| | 11 |
|
Total Purchased Power | 745 |
| | 604 |
| | 39 |
| | 30 |
|
Transmission and Other PPFAC Recoverable Costs | — |
| | — |
| | 10 |
| | 7 |
|
Increase (Decrease) to Reflect PPFAC Recovery Treatment | — |
| | — |
| | (9 | ) | | 5 |
|
Total Generation and Purchased Power | 4,051 |
| | 4,050 |
| | $ | 132 |
| | $ | 129 |
|
Less Line Losses and Company Use | 248 |
| | 224 |
| | | | |
Total Power Sold | 3,803 |
| | 3,826 |
| | | | |
|
| | | | | | | | | | | | | |
| Nine Months Ended September 30, |
(in millions) | 2017 | | 2016 | | 2017 | | 2016 |
Coal-Fired Generation | 5,764 |
| | 5,958 |
| | $ | 138 |
| | $ | 139 |
|
Gas-Fired Generation | 2,348 |
| | 2,711 |
| | 76 |
| | 74 |
|
Utility Owned Renewable Generation | 65 |
| | 51 |
| | — |
| | — |
|
Reimbursed Fuel Expense, Springerville Units 3 and 4 (1) | — |
| | — |
| | 4 |
| | 4 |
|
Total Generation | 8,177 |
| | 8,720 |
| | 218 |
| | 217 |
|
Purchased Power, Non-Renewable | 1,912 |
| | 1,022 |
| | 75 |
| | 35 |
|
Purchased Power, Renewable | 525 |
| | 525 |
| | 32 |
| | 37 |
|
Total Purchased Power | 2,437 |
| | 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 Power | 10,614 |
| | 10,267 |
| | $ | 328 |
| | $ | 326 |
|
Less Line Losses and Company Use | 613 |
| | 575 |
| | | | |
Total Power Sold | 10,001 |
| | 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 |
Coal | 2.54 |
| | 2.23 |
| | 2.40 |
| | 2.34 |
|
Gas | 3.16 |
| | 3.07 |
| | 3.23 |
| | 2.73 |
|
Purchased Power, Non-Renewable | 4.88 |
| | 4.16 |
| | 3.93 |
| | 3.11 |
|
Purchased Power, Renewable | 6.48 |
| | 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.
Operating Revenues
The following table provides a disaggregation of Operating Revenues: | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | Increase (Decrease) | | | | |
(in millions) | 2024 | | 2023 | | Percent | | | | | | |
Operating Revenues | | | | | | | | | | | |
Retail | $ | 282 | | | $ | 233 | | | 21.0 | % | | | | | | |
Wholesale, Short-Term (1) | 84 | | | 94 | | | (10.6) | % | | | | | | |
Wholesale, Long-Term | 19 | | | 29 | | | (34.5) | % | | | | | | |
Transmission | 14 | | | 17 | | | (17.6) | % | | | | | | |
Springerville Units 3 and 4 Participant Billings | 36 | | | 27 | | | 33.3 | % | | | | | | |
Other | 18 | | | 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.
The following table provides key statistics impacting Operating Revenues: | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | Increase (Decrease) | | | | |
(kWh in millions) | 2024 | | 2023 | | Percent | | | | | | |
Electric Sales (kWh) (1) | | | | | | | | | | | |
Retail Sales | 1,795 | | | 1,822 | | | (1.5) | % | | | | | | |
Wholesale, Long-Term | 317 | | | 474 | | | (33.1) | % | | | | | | |
Wholesale, Short-Term | 1,533 | | | 941 | | | 62.9 | % | | | | | | |
Total Electric Sales | 3,645 | | | 3,237 | | | 12.6 | % | | | | | | |
| | | | | | | | | | | |
Average Revenue per kWh (2) | | | | | | | | | | | |
Retail | 15.71 | | | 12.78 | | | 22.9 | % | | | | | | |
Wholesale, Long-Term | 5.85 | | | 6.07 | | | (3.6) | % | | | | | | |
Wholesale, Short-Term | 3.73 | | | 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.
The following table provides key statistics impacting Fuel and Purchased Power: | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | Increase (Decrease) | | | | |
(kWh in millions) | 2024 | | 2023 | | Percent | | | | | | |
Sources of Energy | | | | | | | | | | | |
Coal-Fired Generation | 936 | | | 981 | | | (4.6) | % | | | | | | |
Gas-Fired Generation | 1,892 | | | 1,582 | | | 19.6 | % | | | | | | |
Utility-Owned Renewable Generation | 198 | | | 230 | | | (13.9) | % | | | | | | |
Total Generation | 3,026 | | | 2,793 | | | 8.3 | % | | | | | | |
Purchased Power, Non-Renewable | 403 | | | 179 | | | 125.1 | % | | | | | | |
Purchased Power, Renewable | 318 | | | 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) | | | | | | | | | | |
Coal | 5.43 | | | 2.91 | | | 86.6 | % | | | | | | |
Natural Gas (3) | 2.62 | | | 5.98 | | | (56.2) | % | | | | | | |
Average Cost of Purchased Power (4) | | | | | | | | | | | |
Purchased Power, Non-Renewable | 1.36 | | | 9.20 | | | (85.2) | % | | | | | | |
Purchased Power, Renewable | 6.75 | | | 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
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.
|
| | | |
(in millions) | September 30, 2017 |
Cash and Cash Equivalents | 70 |
|
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 | |
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.
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.
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.
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.
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.
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.
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.
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.