East Kentucky Power Cooperative Rate Case Order Approves Revenue Increase and Settlement

COMMONWEALTH OF KENTUCKY BEFORE THE PUBLIC SERVICE COMMISSION In the Matter of:

O R D E R On August 1, 2025, East Kentucky Power Cooperative (EKPC) pursuant to KRS 278.180, KRS 278.190, and 807 KAR 5:001, filed an application requesting a general adjustment of rates; approval of proposed changes to rate design; approval of EKPC's depreciation study; approval of modifications to several existing tariffs; approval

of EKPC's proposed tracking and recovery mechanism for Regional Transmission

Expansion Plan (RTEP) expenses; approval of EKPC's request to end the Earnings Mechanism (EM) that was established in Case No. 2021-00103; approval to amortize 1

and reset EKPC's Generation Maintenance Tracker in base rates; recovery of reasonable

rate case expense over a period of three years; relief from certain ongoing reporting and filing obligations; and to realign the filing of EKPC's small power production and cogeneration rates to a biennial basis in accordance with 807 KAR 5:054. 2

Case No. 2021-00103, Electronic Application of East Kentucky Power Cooperative, Inc. for a 1 and Other General Relief (Ky. PSC Sept. 30, 2021). ELECTRONIC APPLICATION OF EAST )

KENTUCKY POWER COOPERATIVE, INC. FOR ) Application (filed Aug. 1, 2025) at 14-15. 2A GENERAL ADJUSTMENT OF RATES, ) CASE NO. APPROVAL OF DEPRECIATION STUDY, ) 2025-00208 AMORTIZATION OF CERTAIN REGULATORY ) ASSETS, AND OTHER GENERAL RELIEF )

BACKGROUND EKPC is a not-for-profit, rural electric cooperative corporation established under KRS Chapter 279. EKPC provides electric generation capacity and electric energy to 3 sixteen Owner-Member Cooperatives, which service over 570,000 Kentucky homes, farms, commercial, and industrial establishments in 89 Kentucky counties. EKPC owns 4 and operates approximately 2,963 megawatts (MW) of net summer generating capacity and 3,265 MW of net winter generating capacity. 5 In its application, EKPC proposed an overall revenue increase of $79,757,474 to achieve a TIER of 1.5, which equated to an increase of approximately 7.49 percent above 2023 base rate revenues. However, EKPC stated that, due to rounding, the proposed 6 rate design yielded an increase in revenues of $79,731,915, which was less than EKPC's calculated revenue deficiency. 7 The Attorney General of the Commonwealth of Kentucky, by and through the Office of Rate intervention (Attorney General) and Nucor Steel Gallatin, LLC (Nucor) 8 9 were granted intervention in this proceeding. On December 5, 2025, the Attorney General and Nucor (Attorney General/Nucor or Intervenors) filed a memorandum of understanding

Application at 1. 3 Application at 1. 4 Application at 1. 5 Direct Testimony of Jeffrey Wernert (Wernert Direct Testimony) at 15. 6 Wernert Direct Testimony at 17. 7 Order (Ky. PSC July 10, 2025). 8 Order (Ky. PSC Aug. 19, 2025). 9

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as to the sharing of witnesses that was effective on August 8, 2025. On August 22, 10 2025, Appalachian Citizens' Law Center, Kentuckians for the Commonwealth, Kentucky Solar Energy Society, and Mountain Association filed a joint motion for full intervention as joint intervenors, and on September 19, 2025, the Commission denied the request. 11 12 By Order entered August 14, 2025, the Commission suspended the proposed rates up to and including January 31, 2026, and established a procedural schedule. On August 14, 13 2025, EKPC filed a motion for an extension of time to respond to Commission Staff's First Request for Information, and on August 15, 2025, the Attorney General and the 14 Kentucky Industrial Utility Customers (KIUC) (together, Attorney General/KIUC) filed a

Joint Response to EKPC's Motion for Extension of Time and an Alternative Motion to

Modify the Procedural Schedule. Both motions were granted on August 21, 2025. 15 16 Pursuant to the amended procedural schedule established on August 21, 2025, the

The Attorney General and Nucor's Memorandum of Understanding (filed Dec. 5, 2025). 10 Joint Motion of Appalachian Citizens' Law Center, Kentuckians for the Commonwealth, Kentucky 11Solar Energy Society, and Mountain Association for Full Intervention as Joint Intervenors (filed Aug. 22, 2025). Order (Ky. PSC Sept. 19, 2025). 12 Order (Ky. PSC Aug. 14, 2025). 13 EKPC's Motion for Extension of Time (filed Aug. 14, 2025). 14 Joint Response of Attorney General and KIUC to EKPC's Motion for Extension of Time to File 15Responses to Commission Staff's Initial Data Requests; Alternative Motion to Modify the Procedural Schedule (filed Aug. 15, 2025). While the motion lists KIUC, this was likely an error listing KIUC rather than Nucor. Order (Ky. PSC Aug. 21, 2025). 16

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parties filed direct and rebuttal testimony, and responded to multiple rounds of discovery 17 from Commission Staff and the Intervenors. An informal technical conference (ITC) was 18 held on August 26, 2025. By Order dated October 8, 2025, a hearing was scheduled in 19 this matter to begin on December 8, 2025. On November 24, 2025, a Joint Stipulation, 20 Settlement Agreement and Recommendation (Joint Settlement) from EKPC, the Attorney General, and Nucor (the Parties) was filed by EKPC into the record along with supplemental testimony from Cliff Scott, Executive Vice President and Chief Financial Officer for EKPC, and Jacob Watson, Manager of Rates and Regulatory for EKPC. 21 formal hearing was held on December 8, 2025. EKPC responded to one post-hearing request for information from Staff, which had two supplemental filings, and one post-

AAttorney General's and Nucor's Direct Testimony of Stephen J. Baron (Baron Direct Testimony) 17(filed Oct. 24, 2025). Attorney General's and Nucor's Direct Testimony of Randy Futral (Futral Direct Testimony) (filed Oct. 24, 2025). Attorney General's and Nucor's Direct Testimony of Lane Kollen (Kollen Direct Testimony) (filed Oct. 24, 2025). EKPC's Rebuttal Testimony of John J. Spanos (Spanos Rebuttal Testimony) (filed Dec. 2, 2025). EKPC's Rebuttal Testimony of Jacob Watson (Watson Rebuttal Testimony) (filed Dec. 2, 2025). EKPC's Rebuttal Testimony of Jeffrey W. Wernert (Wernert Rebuttal Testimony) (filed Dec. 2, 2025). EKPC's Response to Staff's First Request for Information (Staff's First Request) (filed Aug. 22, 182025). EKPC's Response to Staff's Second Request for Information (Staff's Second Request) (filed Sep. 17, 2025). EKPC's Response to Attorney General's and Nucor's First Request for Information (The Attorney General/Nucor's First Request) (filed Sep. 17, 2025). EKPC's Supplemental Response to Attorney

General's and Nucor's First Request for Information (The Attorney General/Nucor's First Request) (filed Sep. 24, 2025). EKPC's Second Supplemental Response to the Attorney General/Nucor's First Request

(filed Sep. 26, 2025). EKPC's Third Supplemental Response to the Attorney General/Nucor's First Request

(filed Oct. 1, 2025). EKPC's Response to Staff's Third Request for Information (Staff's Third Request) (filed Oct. 13, 2025). EKPC's Response to Attorney General's and Nucor's Second Request for Information (The Attorney General/Nucor's Second Request) (filed Oct. 13, 2025). Attorney General's and Nucor's Response to EKPC's First Request for Information (EKPC's First Request) (filed Nov. 21, 2025).

Order (Ky. PSC Aug. 14, 2025). 19 Order (Ky. PSC Oct. 8, 2025). 20 Joint Stipulation and Settlement Agreement (Joint Settlement) (filed Nov. 24, 2025). EKPC's 21Supplemental Testimony of Cliff Scott (Scott Supplemental Testimony) (filed Nov. 24, 2025). EKPC's Supplemental Testimony of Jacob Watson (Watson Supplemental Testimony) (filed Nov. 24, 2025).

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hearing request for information from the Intervenors. EKPC filed a post-hearing brief 22 on December 24, 2025 and the Attorney General/Nucor filed a post-hearing brief on 23 December 22, 2025. This matter now stands submitted for a decision. 24 LEGAL STANDARD Pursuant to KRS 278.030(1), the Commission's statutory obligation when

reviewing a rate application is to determine whether the proposed rates are "fair, just and reasonable." EKPC bears the burden of proof to show that the proposed rates are just 25 and reasonable under the requirements of KRS 278.190(3).

EKPC's application also requested approval for the establishment of a regulatory

asset related to PJM Interconnection, LLC (PJM) RTEP expenses. KRS 278.220 provides that the Commission may establish a uniform system of accounts (USoA) for utilities. Pursuant to the statute, the system of accounts should conform as nearly as practicable to the system adopted or approved by the Federal Energy Regulatory Commission (FERC). The FERC USoA provides for regulatory assets, or the capitalization of costs that would otherwise be expensed but for the actions of a rate

regulator. The Financial Accounting Standards Board's Statement of Financial

Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation,

EKPC's Response to Commission Staff's Post-Hearing Request for Information (Staff's Post-22Hearing Request) (filed Dec. 19, 2025). EKPC's Response to the Attorney General and Nucor's Post- Hearing Request for Information (The Attorney General/Nucor's Post-Hearing Request) (filed Dec. 19, 2025). EKPC's Supplemental Response to Staff's Post-Hearing Request for Information (Staff's Post- Hearing Request) (filed Jan. 9, 2026). EKPC's Second Supplemental Response to Staff's Post-Hearing

Request for Information (Staff's Post-Hearing Request) (filed Jan. 21, 2026).

EKPC's Post-Hearing Brief (filed Dec. 24, 2025). 23 The Attorney General and Nucor's Post-Hearing Brief (filed Dec. 22, 2025). 24 KRS 278.030; Public Service Commission v. Com. Ex rel. Conway, 324 S.W.3d 373, 377 (Ky. 252010).

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which was codified as Accounting Standards Codification (ASC) 980, Regulated Operations, provides the criteria for recognition of a regulatory asset. Pursuant to ASC 26 980, it must be probable that the utility will recover approximately equal revenue through the inclusion of these costs for ratemaking purposes, with the intent to recover the previously incurred cost not a similar future cost. In prior matters, the Commission has identified, generally, parameters for expenses for regulatory asset treatment and has approved regulatory assets when a utility has incurred (1) an extraordinary, nonrecurring expense which could not have reasonably been anticipated or included in the utility's planning; (2) an expense resulting from a statutory or administrative directive; (3) an expense in relation to an industry sponsored initiative; or (4) an extraordinary or nonrecurring expense that over time will result in a saving that fully offsets the cost. 27 Additionally, the Commission has previously issued orders indicating that utilities should

ASC 980-340-25-1 provides, in full, as follows: 26 25-1 Rate actions of a regulator can provide reasonable assurance of the existence of an asset. An entity shall capitalize all or part of an incurred cost that would otherwise be charged to expense if both of the following criteria are met:

1. It is probable (as defined in Topic 450) that future revenue in an amount
   at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for rate-making purposes.

2. Based on available evidence; the future revenue will be provided to
   permit recovery of the previously incurred cost rather than to provide for expected levels of similar future costs. If the revenue will be provided through an automatic rate-adjustment clause, this criterion requires that the regulator's intent clearly be to permit recovery of the previously incurred cost. A cost that does not meet these asset recognition criteria at the date the cost is incurred shall be recognized as a regulatory asset when it does meet those criteria at a later date. Case No. 2008-00436, Application of East Kentucky Power Cooperative, Inc. for an Order 27 Approving Accounting Practices to Establish a Regulatory Asset Related to Certain Replacement Power Costs Resulting from Generation Forced Outages (Ky. PSC Dec. 23, 2008), Order at 3-4.

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generally seek Commission approval before recording regulatory assets, and 28 requirements regarding the timing for applications seeking such approval. Outside of 29 the prescribed categories of expenses that qualify for regulatory asset treatment, utilities have established regulatory assets for certain timing and accounting differences, such as over- or under-recoveries for riders. Even though EKPC, the Attorney General, and Nucor filed a Joint Settlement that purports to resolve all the issues in the pending application, the Commission cannot forego its responsibility to determine what constitutes fair, just and reasonable rates. The Commission must review the record in its entirety, including the Joint Settlement, and apply its expertise to make an independent decision as to the level of rates, including terms and conditions of service, that should be approved. JOINT SETTLEMENT The Joint Settlement reflects the agreement between EKPC, the Attorney General, and Nucor addressing all the issues in the application. The material provisions of the Joint Settlement are as follows:

• The overall base rate revenue requirement resulting from the stipulated adjustments is $1,128,049,682. This represents an increase in $63,727,181 over 30 the test year revenue that would be collected at current rates. 31

Case No. 2016-00180, Application of Kentucky Power Company for an Order Approving 28 Accounting Practices to Establish Regulatory Assets and Liabilities Related to the Extraordinary Expenses Incurred by Kentucky Power Company in Connection with the Two 2015 Major Storm Events (Ky. PSC Nov. 3, 2016), Order at 9. Case No. 2016-00180, Dec. 12, 2016 Order at 5. 29 Joint Settlement at 2 and Exhibit C; $1,128,049,682 = $1,064,322,501 + $63,727,181 30 Joint Settlement at 2 and Exhibit A. 31

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• The Parties agreed the foregoing revenue requirement would be allocated as
  follows: 32

• The Parties agreed that EKPC should be authorized to continue earning a 1.50
  Times Interest Earned Ratio (TIER) for base rates. 33

• The Parties agreed that EKPC should implement a Symmetrical Earnings
  Mechanism (SEM). Through the SEM, EKPC would collect or return any margins to its Owner-Members for contemporaneous collection or pass-through to Retail Members in the form of a bill charge or credit in the event that EKPC's per book margins fall below a 1.4 TIER or are in excess of a 1.60 TIER in any calendar year. The SEM would remain in place until EKPC's base rates are next adjusted but may be renewed at that time. 34

• The Parties agreed that EKPC shall amend the 25-year-old Pumping Station
  Special Contract to eliminate the existing subsidy by either: 1) updating transmission costs from the 2000 level and including PJM generation capacity cost in a market-based contract; or 2) place the 31.9-megawatt (MW) gas utility on a standard cost-of-service rate. 35

• The Parties agreed that EKPC shall increase the interruptible credit by $2.00 per
  kilowatt (KW) per month for its 28 existing interruptible customers as well as any prospective interruptible customers. 36

Joint Settlement at 3 and Exhibit C which notes a ($1,162) difference from the Target Revenue, 32or (0.002) percent.

33 34 35 36

-8- Case No. 2025-00208 Rate E 39,726,834$ 4.95%Rate B 7,389,438 9.64%Rate C 2,917,291 9.64%Rate G 4,405,247 9.64%Contract Steam 1,344,423 9.64%Large Special Contract 7,942,786 9.64%Pumping Stations 0 0.00%Total 63,726,019$ 5.99%Rate Class Increase Increase Amount Percentage

• The Parties agreed, except as noted in the removal of terminal net salvage from fossil generation in the revenue requirement, EKPC's proposed depreciation study

and related accounting treatments should be approved with an effective date for the new depreciation rates to be the same day that EKPC's new rates become effective. 37

• The Parties agreed that the three regulatory assets identified in EKPC's application
  are acknowledged to be included within its revenue requirement and would be approved as proposed: 38

• Extending the amortization for the cancellation of the Smith Unit 1
  generation station that was authorized in Case No. 2010-00449, and 39 consistent with the provisions of the Stipulation Agreement approved in Case No. 2015-00358, for six years; 40

• Amortizing the Generation Maintenance regulatory asset for six years;

• Amortizing the RTEP regulatory asset that was approved by the
  Commission in Case No. 2025-00193 for six years. 41 42

• The Parties agreed that EKPC should no longer be required to make certain
  informational filings with the Commission that appear to be obsolete:

• Annual comprehensive report identifying benefits and costs that accrue
  from its PJM membership and comparing these to benefits and costs if EKPC left PJM as modified in Case No. 2021-00103 and originally from 43 Case No. 2012-00169; and 44

37 38

Case No. 2010-00449, Application of East Kentucky Power Cooperative, Inc. for an Order 39 Approving the Establishment of a Regulatory Asset for the Amount Expended on its Smith 1 Generating Unit (Ky. PSC Feb. 28, 2011). Case No. 2015-00358, Application of East Kentucky Power Cooperative, Inc. for Deviation from 40Obligation Resulting from Case No. 2012-00169 (Ky. PSC Jan. 10, 2017). Case No. 2025-00193, Electronic Application of East Kentucky Power Cooperative, Inc. for an 41 Order Approving The Establishment of a Regulatory Asset for the Expenses Associated with the Regional Sept. 29, 2025).

Case No. 2021-00103 Electronic Application of East Kentucky Power Cooperative, Inc. for a 43 and Other General Relief (Ky. PSC Sept. 30, 2021) Order, as modified by Order issued May 25, 2022). Case No. 2012-00169 Application of East Kentucky Power Cooperative, Inc. to Transfer 44Functional Control of Certain Transmission Facilities to PJM Interconnection, LLC (Ky. PSC Dec. 20, 2012).

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• Annual operating reports setting forth details of the performance of the
  Bluegrass Station from Case No. 2015-00267. 45

• The Parties agreed that EKPC's request to realign the filing of its small power
  production and cogeneration rates to a biennial basis in accordance with 807 KAR 5:054. 46

• The Parties agreed that all proposed modifications to EKPC's tariffs should be
  approved as set forth in the application. 47

• The Parties agreed that EKPC should be authorized to recover its reasonable rate
  case expense, including the amounts for its Owner-Members' pass-through rate application cases, on an amortized basis over three years. 48

• EKPC agreed to a minimum three-year rate case stay-out, as described in further
  detail in the settlement. 49 On January 9, 2026, the Joint Settlement was updated to include final Rate Case Expense amounts, which resulted in an updated Joint Settlement revenue increase amount of $63,693,031. 50 ANALYSIS AND DETERMINATION The Commission remains a creature of statute, and its authority is limited to the powers granted to it by the Kentucky General Assembly (General Assembly). As part of that mandate, the Commission must ensure that all rates meet the requirements of KRS Chapter 278, and while the Commission generally finds the proposed Joint Settlement

Joint Settlement at 7; Case No. 2015-00267, Application of East Kentucky Power Cooperative, 45 Inc. for Approval of the Acquisition of Existing Combustion Turbine Facilities from Bluegrass Generation Company, LLC at the Bluegrass Generating Station in Lagrange, Oldham County, Kentucky and for Approval of the Assumption of Certain Evidences of Indebtedness (Ky. PSC Dec. 1, 2015).

46 47 48 49

EKPC's Updated Response to Staff's Post-Hearing Request for Information (filed Jan. 9, 2026), 50Exhibit A.

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appropriate, it is unable to approve the Joint Settlement without modification. In doing so, the Commission recognizes the good faith efforts of all parties involved in the Joint Settlement in providing a full record of all material issues in this case. Therefore, as will be explained in detail below, the Commission accepts the Joint Settlement reached by the Parties, subject to certain modifications contained herein. The modifications are necessary to ensure fair, just and reasonable rates. The effect of the Commission's adjustments and modifications to the Joint Settlement is a total revenue requirement increase of $63,670,273, which includes the authorized TIER of 1.50. This reflects a $16,087,201, decrease of EKPC's requested revenue requirement increase of $79,757,474 and an approximate $22,758 decrease from the Joint Settlement revenue 51 requirement increase of $63,693,031. 52 As discussed more fully below, the Commission finds that the Parties' request in the Joint Settlement to implement a Symmetrical Earnings Mechanism should be denied. Given the denial of the Symmetrical Earnings Mechanism, the Commission reviewed the

Parties' arguments to end or maintain the previously approved Earnings Mechanism and finds that EKPC's request to terminate the Earnings Mechanism should be approved. The Commission also accepts EKPC's original request for a proposed tracking and

recovery mechanism for RTEP expenses and changes associated with the generation maintenance tracker. The adjustments and amortization periods associated with these

Watson Testimony at 5, stating the revenue deficiency of $79,757,474 represents the precise 51mathematical requirement resulting from pro forma adjustments and the application of a 1.50 TIER. This figure serves as the calculated benchmark for the test year. The revenue increase of $79,731,915 reflects the actual revenue to be recovered through proposed base rates, with the minor variance attributable to rounding conventions applied during the functional rate design process. See Appendix A. 52

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trackers are discussed in the revenue requirement section below as the RTEP Tracker. 53 The overall reasonableness of the trackers is discussed in separate sections below. 54

The Commission also approves EKPC's proposals related to its interruptible

credits; Bluegrass Station reporting requirements; Co-Generation/Small Power Production tariff; tariff updates; and proposed tariff changes. The Commission modifies the Joint Settlement by requiring EKPC to file a report, as required by Case No. 2021- 00103, related to membership in PJM within the context of its next integrated resource plan (IRP) filing until further Order of this Commission but relieves EKPC of its annual filing requirement. TEST PERIOD EKPC used a historical test period of the 12-month period ending December 31, 2023, and, except where noted, included known and measurable adjustments through the period ending on June 30, 2024. No intervenor contested the use of this period as 55 the test period. The Commission finds that it is reasonable to use the 12-month period ending December 31, 2023, with known and measurable adjustments through the period ending on June 30, 2024.

See page 50. 53 See page 63. 54 Application at 4. 55

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REVENUE REQUIREMENT Revenue and Expense Adjustments In its application, EKPC proposed 29 adjustments to normalize its test-year operating revenue and expenses. These adjustments were proposed also in the Joint 56 Additionally, pursuant to the Joint Settlement, the Parties proposed six 57

additional adjustments to EKPC's proposed revenue increase. The Commission finds the

following adjustments set forth in the Joint Settlement went largely uncontested throughout the pendency of this case, are reasonable and should be accepted without change: 58

• Remove Fuel Adjustment Clause (FAC) from Base Rates: $9,319 59
• Remove Environmental Surcharge (ES) from Base Rates: ($13,887,667) 60
• Remove ES from Off-System Sales: ($657,368) 61
• Increase Interest Income: $2,864,733 62 Application, Exhibit 16, Attachment JRW-1, Statement of Operations. 56 Joint Settlement at 8. 57 The Commission notes that the amounts shown reflect the impact of the adjustments on the 58individual expense category and do not reflect the net impact of the adjustments unless otherwise specified below. Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.01. 59 Net Impact of FAC Adjustments = (Fuel Costs in Base Rates) + (Member FAC Billings) + (Total Accrued FAC) - (Fuel Costs Recoverable through FAC) - (Purchased Power Recoverable through FAC) - (PJM Costs Recoverable through FAC) = ($341,554,580) + ($133,649,531) + $15,889,496 - ($327,966,613) - ($127,934,541) - ($3,422,780) = $9,319. Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.02. 60 Net Impact of Base Rate ES Adjustments = (Surcharge Revenues) + (Accrued ES) - (Surcharge Expenses) - (Emissions Expense) - (Insurance Expense) - (Property Taxes) - (Depreciation Expense) - (ARO Amortization Expense) - (ARO Accretion Expense) - (Interest on Long-Term Debt) = ($144,568,536) + ($4,557,470) - ($56,225,551) - ($21,828) - ($1,425,714) - ($1,924,723) - ($48,239,966) - ($5,753,866)

- ($1,449,732) - ($20,196,960) = $(13,887,667)

Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.03. 61 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.05. 62

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• Increase Wages and Salaries: $1,538,091 63
• Increase Payroll Taxes: $95,328 64
• Increase Employee Medical Insurance Expense: $178,773 65
• Remove Employee Benefit Expenses: ($826,139) 66
• Remove Miscellaneous Employee Benefit Expenses: ($427,310) 67
• Increase Retiree Medical Insurance Expense: $918,963 68
• Remove Advertising Expenses Pursuant to 807 KAR 5:016: ($174,119) 69
• Remove Board of Directors' Expenses: ($98,967) 70
• Remove Donations: ($138,430) 71
• Remove Touchstone Energy Dues and Expenses: ($443,873) 72
• Remove Non-Recurring and Other Expenses: ($1,059,398) 73

• Reduce Forced Outage and Highest Purchased Power Costs not
  Recovered through FAC: ($632,124) 74

• Increase Insurance Expense: $1,060,469 75

• Reduce RTEP Expenses: ($737,023) 76

• Remove Capacity Performance Payments from PJM: ($24,279,543) 77
  Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.06. 63 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.07. 64 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.08. 65 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.09. 66 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.10. 67 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.11. 68 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.12. 69 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.13. 70 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.14. 71 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.16. 72 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.17. 73 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.20. 74 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.21. 75 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.22. 76 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.24. 77

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• Remove Generation Maintenance Expense in Excess of Tracker
  Mechanism: ($6,088,203) 78

• Remove Amortization of Regulatory Asset associated with the Dale
  Asbestos and Dale ES Projects 5 and 10: ($791,263) 79

• Increase PSC Assessment: $132,899 80
  The Commission finds it should modify EKPC's other proposed adjustments and make additional adjustments as discussed in more detail below. The Commission notes that the following adjustments were contested by at least one party to this proceeding and are therefore further discussed below, regardless of whether the Commission modified the Joint Settlement or not. A summary of all the Commission's adjustments is on page

Weather Normalization In its application, EKPC did not propose an adjustment to Non-FAC Base Revenues to Account for Weather Normalization. Prior to the Stipulation, the Attorney General/Nucor proposed a weather normalization adjustment to revenues which increased test year revenues by $34,277,416, net of the base fuel and purchased energy component included in base revenues. This adjustment would result in a reduction of $34,330,683 to the requested 81 base revenue increase. The Attorney General/Nucor argued that EKPC's test year 82 revenues were understated because actual sales were significantly lower than normal

Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.25. 78 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.28. 79 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.29. 80 Kollen Direct Testimony at 10. 81 Kollen Direct Testimony at 7-10. 82

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due to warmer temperatures during the heating season, specifically that the winter heating season in 2023 was 21.9 percent warmer than normal. 83

General/Nucor further argued that according to EKPC's most recent IRP, 2023 energy

sales were 756,662,000 kWh lower than would have occurred under normal weather conditions, and that heating degree days in 2023 were the lowest during the 25-year period 2000 to 2024. 84 In rebuttal, EKPC recommended utilizing the historical test year without a weather normalization adjustment. EKPC argued that a historical test year was utilized because 85 costs and revenues were known and measurable, and the revenues and expenses associated with operating are matched. EKPC stated weather normalizing revenues 86 without adjusting the expenses associated with serving increased sales with weather normalizing revenues breaks this matching principle. EKPC stated that a single extreme 87 cold or hot weather event can pull the annual totals back toward normal on paper, even though the year itself was anything but normal from an operational standpoint. EKPC 88 argued that the weather normalization process belongs in operational planning to serve

future load, but does not belong in the game of "what if" in a rate case. 89

Kollen Direct Testimony at 7. 83 Kollen Direct Testimony at 7. 84 Watson Rebuttal Testimony at 4. 85 Watson Rebuttal Testimony at 4. 86 Watson Rebuttal Testimony at 4. 87 Watson Rebuttal Testimony at 4. 88 Watson Rebuttal Testimony at 4. 89

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EKPC argued that the weather normalization values the Attorney General/Nucor

used were from EKPC's operational load forecasts which were conducted by RUS Form 7 classifications, not EKPC's rate class, and the total weather normalization adjustment

was allocated across rate classes without any regard for the rate class relationship to weather. Lastly, EKPC argued there was no consideration to other billing implications 90 such as minimum energy bills or power factor penalties. EKPC stated that when making 91 a weather normalization adjustment, it would be conceivable that some minimum energy billings would no longer occur with increased energy sales, which would also be true to power factor penalties. EKPC argued that the Attorney General/Nucor's proposed 92 adjustment did not take into account any of the billing determinants that could change or the costs associated with serving the increased demand or energy. EKPC 93

recommended that the Commission reject the Attorney General/Nucor's proposed

adjustment for weather normalization. 94

In the Joint Settlement, there was no weather normalization adjustment to EKPC's

revenue requirement.

Commission finds the Non-FAC Base Revenues amounts are reasonable and should be accepted, consistent with the Joint Settlement. The Commission finds that the Attorney General/Nucor's original proposed adjustment is unreasonable and should be denied.

Watson Rebuttal Testimony at 5. 90 Watson Rebuttal Testimony at 5. 91 Watson Rebuttal Testimony at 5. 92 Watson Rebuttal Testimony at 5. 93 Watson Rebuttal Testimony at 5. 94

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The Commission agrees with EKPC's argument that, in utilizing a historic test year, the

costs and revenues are known, and operating revenues and costs should be matched.

As EKPC noted, the Attorney General/Nucor's proposed weather normalization

adjustment does not take into account the increased costs that coincide with increased revenues.

The Commission agrees with EKPC's arguments that, should a weather

normalization adjustment be utilized, it should consider both the increased expenses

associated with serving increased sales, as well as the rate class's relationships to

weather. However, while the utility has control over the structure and presentation of its rate case, including the test year, the Commission acknowledges the milder weather in

EKPC's test year and notes that EKPC acknowledged the irregularity as well. As such, 95 the Commission expects, in future proceedings where such anomalies exist within the test year, that EKPC consider the implications of irregular test year revenues and be prepared to justify their use in setting future rates. Customer Growth Normalization In its application, EKPC did not propose an adjustment to non-fuel revenues to account for customer growth.

Prior to the settlement, the Attorney General/Nucor argued that EKPC's test year

revenues were understated because there was member cooperative customer growth through the test year which continued through June 30, 2024. 96 General/Nucor stated that they asked EKPC to provide calculations of annualized non-

Application, Exhibit 12, Direct Testimony of Anthony S. Campbell (Campbell Direct Testimony) 95(filed Aug. 1, 2025) at 6. Kollen Direct Testimony at 10. 96

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fuel revenues at the end of the test year and through June 30, 2024, to match the timing of adjustments to expenses proposed by EKPC, but EKPC did not provide the information. EKPC responded that it believed the actual allowable expenses should be 97 paired with actual revenues that were incurred during the historic test year used in the development of this case. EKPC further stated that adjusting revenues for annualized 98 customer counts would create a disconnect between the revenues collected and the costs incurred by EKPC during the test year. 99 The Attorney General/Nucor argued that the Commission has repeatedly adopted adjustments proposed by utilities using a historic test year to annualize base revenues for customer growth. The Attorney General/Nucor further argued that this adjustment 100 is highly relevant to the revenue requirement in this proceeding. 101 General/Nucor further recommended that the Commission direct EKPC to provide an adjustment to annualize base revenues for member cooperative customer growth at the end of the test year and at six months after the end of the test year in future base revenue proceedings in EKPC uses a historic test year. 102

Kollen Direct Testimony at 11. 97 Kollen Direct Testimony at 12. 98 Kollen Direct Testimony at 12. 99 Kollen Direct Testimony at 12. 100 Kollen Direct Testimony at 12. 101 Kollen Direct Testimony at 13. 102

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EKPC further stated that adjusting revenues for annualized customer counts would create a disconnect between the revenues collected and the costs incurred by EKPC during the test year. 103 The Joint Settlement did not include Customer Growth Normalization adjustment to non-fuel revenues from EKPC's test year revenue requirement.

Commission finds that the amount of non-fuel revenues is reasonable and should be accepted, consistent with the Joint Settlement. Similar to the weather normalization adjustment discussed above, the Attorney General/Nucor's original proposed adjustment to increase revenues based on customer growth did not take into account the increase in costs that coincide with an increased customer base. Therefore, the Commission finds that the Attorney General/Nucor's proposed adjustment to increase EKPC's revenues to account for customer growth is unreasonable and should be rejected. However, should EKPC continue to utilize a historic test year that is so far removed from the timing of the processing of its application, EKPC should make adjustments for both revenues and expenses that reflect known and measurable changes. In addition, the Commission may consider the information the Attorney General/Nucor requested but that consideration does not prevent EKPC from presenting evidence or arguments that the data either should not be utilized or used in a different manner. To not provide the data because the utility did not see it as appropriate does not allow for the Commission to weigh the evidence as the fact finder in the administrative proceeding, and may result in a negative inference being drawn against the party failing to provide requested information without

EKPC's Response to the Attorney General/Nucor's First Request, Item 22. 103

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leave from the Commission. In particular, the Attorney General has a statutory right for intervention in a case and is authorized by the legislature as the ratepayer advocate on behalf of all ratepayers in the Commonwealth. EKPC is put on notice that the Commission, not the utility, will make the determination on whether or not data is appropriate in a proceeding in front of the Commission. Any effort to be unresponsive rather than raising proper objection to the Commission may be perceived as an effort to prevent both the Attorney General and the Commission from carrying out their statutory obligations and will be dealt with in an appropriate manner by the Commission in future proceedings. Interest Expense on Long-Term Debt In its application, EKPC proposed an adjustment of $171,226 to increase and normalize its test year actual interest expense on long-term debt based on interest rates as of June 30, 2024. Prior to the Joint Settlement, the Attorney General/Nucor argued 104 that EKPC did not remove the appropriate amount of annualized long-term debt interest expense tied to its projects that would be recoverable through its Environmental Surcharge (ES). The Attorney General/Nucor recommended that the Commission 105 require that the amount of ES long-term debt interest expense removed from base rate consideration equal the actual interest expense reflected in the ES filings, since that was the amount recovered from ratepayers outside of base rates. 106 General/Nucor further recommended that the Commission require the use of the ES filing

Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.04. 104 Futral Direct Testimony at 22. 105 Futral Direct Testimony at 24. 106

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rate base as of December 31, 2023, of $747,239,766 and the ES debt rate of 4.398 percent as of June 30, 2024, resulting in a reduction of long-term debt interest expense of $4,463,889 and a reduction to EKPC's base revenue requirement of $6,706,238. 107 As part of the Joint Settlement, the Parties agreed not to include the Attorney

General/Nucor's adjustment to reduce EKPC's long-term debt interest expense.

Commission finds that EKPC's original adjustment pertaining to EKPC's long-term debt interest expense should be accepted, consistent with the Joint Settlement. The

Commission finds that EKPC's original adjustment is reasonable and should be accepted

as filed because EKPC's methodology is internally consistent by utilizing a single snapshot date of June, 30, 2024. By applying the actual interest rates and debt balances as of this date, EKPC correctly synchronized the removal of interest related to ES projects with the total interest reported in the base rate filing. The Commission rejects the Attorney

General/Nucor's initially proposed adjustment to base EKPC's interest expense on long-

term debt on its ES filing rate base as of December 31, 2023, since the amounts have been updated through the normalization period of EKPC's test year and relied upon

EKPC's December 2023 debt balances paired with updated June 2024 interest rates. EKPC's pro forma adjustment to normalize its interest expense on long-term debt as filed

increases EKPC's base test year revenue requirement by $171,492.

Futral Direct Testimony at 24. 107

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Lobbying Expense In its application, EKPC proposed a pro forma adjustment to remove $302,719 108 in lobbying expenses from the test year. EKPC noted that, in addition to Account 426.4, 109 EKPC identified lobbying expenses recorded in four other accounts. 110 the adjustment removed lobbying expenses in all five accounts from the test year. 111 The Attorney General/Nucor stated that EKPC included $31,918 for Edison Electric Institute (EEI) dues in the test year with no adjustment to remove costs for lobbying expenses, $90,000 for American's Power Dues in the test year after an adjustment to remove $10,000 for lobbying activities, $532,976 for National Rural Electric 112 113 Cooperative Association (NRECA) dues in the test year, with no adjustment to remove costs for lobbying, and included a total of $4,743 for Kentucky Coal Association (KCA) and Waterways Council, Inc. (WCI) dues in the test year with no adjustment to remove costs for lobbying. The Attorney General/Nucor stated that each of these organizations 114 to which dues were paid and expenses included in the revenue requirement were known to engage in legislative advocacy, regulatory advocacy, and public relations. 115

The expenses removed in lobbying expenses were expenses itemized from Smith-Free Group 108LLC, America's Power, KEC Government Strategies Contribution, and lobby expenses reported to KLEC. Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.15. 109 Direct Testimony of Jacob Watson (Watson Direct Testimony) (filed Aug. 1, 2025) at 20. 110 Watson Direct Testimony at 20. 111 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.14. 112 EKPC Responses to Staff's Post-Hearing First Request, Item 11. 113 Futral Direct Testimony at 17-18; Attorney General/Nucor's EKPC Revenue Requirement (filed 114Oct. 24, 2025) Excel Spreadsheet (Attorney General/Nucor's Workpapers), Dues Tab. Futral Direct Testimony at 18. 115

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Prior to the Joint Settlement, the Attorney General/Nucor argued that the Commission has previously denied the recovery of any EEI dues. 116 General/Nucor recommended that the EEI, America's Power, NRECA, KCA, and WCI dues be removed from the test year in accordance with Commission precedent. The 117 Attorney General/Nucor argued that EKPC failed to provide evidence of a direct ratepayer benefit from its memberships in the trade organizations and there was no evidence that ratepayer-provided dues were not used for legislative advocacy, regulatory advocacy, and/or public relations. This recommendation would result in a reduction of 118 $660,662 to EKPC's proposed revenue requirement and requested base rate 119 increase. 120 In rebuttal, EKPC argued that it removed the portion of NRECA dues that pertained to covered activities and that the Commission historically allowed recovery of the NRECA

Futral Direct Testimony at 18-21; Citing Case No. 2020-00349, Electronic Application of 116 Kentucky Utilities Company for an Adjustment of its Electric Rates, a Certificate of Public Convenience and Necessity to Deploy Advanced Metering Infrastructure, Approval of Certain Regulatory and Accounting Treatments, and Establishment of a One-Year Surcredit (Ky. PSC Jun. 30, 2021), Order at 25-28; Case No 2020-00350, Electronic Application of Louisville Gas and Electric Company for an Adjustment of its Electric and Gas Rates, a Certificate of Public Convenience and Necessity to Deploy Advanced Metering Infrastructure, Approval of Certain Regulatory and Accounting Treatments, and Establishment of a One- Year Surcredit (Ky. PSC Jun. 30, 2021), Order at 27-31; Case No. 2021-00214, Electronic Application of Atmos Energy Corporation for an Adjustment of Rates (Ky. PSC May 19, 2022), Order at 23-25; and Case No. 2024-00276, Electronic Application of Atmos Energy Corporation for an Adjustment of Rates, Approval of Tariff Revisions, and Other General Relief (Ky. PSC Aug. 11, 2025), Order at 26-27. Futral Direct Testimony at 20. 117 Futral Direct Testimony at 20-21. 118 Futral Direct Testimony, at 21; Attorney General/Nucor's Workpapers Revenue Requirement 119Tab, Cell H23. The Commission notes that the Attorney General/Nucor's spreadsheet was rounded to the millions. In order to obtain the whole number, the Commission multiplied the rounded adjustment by one million ($0.661 million * 1,000,000 = $660,662). Futral Direct Testimony at 21. 120

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dues that did not pertain to covered activities. EKPC further stated that the 121

Commission should reject the Attorney General/Nucor's adjustment. EKPC 122 additionally noted that NRECA membership dues that were included for recovery in this proceeding was $532,976 and that during the test year, EKPC was actually invoiced a higher amount of $597,869 from NRECA for dues covering December 2023 through November 2024. EKPC stated it could have normalized the annual NRECA expense 123 to the full invoiced amount of $597,869, but opted not to normalize the NRECA expense and excluded $64,893 instead. EKPC argued that ten percent of NRECA dues are 124 unrecoverable and the exclusion of $64,893 resulted in more than ten percent being excluded from revenue requirement. At the hearing, EKPC acknowledged that the 125

dues for EEI, America's Power, and a portion of the NRECA dues inclusion in the test

period was an oversight, and would otherwise have been removed as lobbying expenses. 126 As a result of the Joint Settlement, the Parties agreed to EKPC's original proposed adjustment to remove $302,719 for organizational membership dues.

Commission finds that the Joint Settlement should be modified to remove EEI, America's

Watson Rebuttal Testimony at 7. 121 Watson Rebuttal Testimony at 7. 122 EKPC's Response to Staff's Post-Hearing Request, Item 11. 123 EKPC's Response to Staff's Post-Hearing Request, Item 11. 124 EKPC's Response to Staff's Post-Hearing Request, Item 11. 125 Hearing Video Transcript (HVT) of Dec. 8, 2025 Hearing, Hearing Testimony of Jacob Watson 126at 04:56:56-04:58:00.

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Power, NRECA, KCA, and WCI dues in the test year consistent with the Attorney

General/Nucor's original recommendation. The Commission finds that the removal of EKPC's membership dues expenses related to organizations who engage in certain

activities such as lobbying, advertising, marketing, legislative policy research, and regulatory policy research is consistent with Commission precedent excluding recovery of expenses without clear evidence of direct ratepayer benefit. Without knowing which 127 costs comprise the percentage of dues attributable to covered activities, the Commission cannot find, with reasonable certainty, that these percentages are based on actual spending in all covered activities, rather than spending attributable to lobbying. For these reasons, the Commission finds that a reduction of $659,637 to EKPC's membership dues

expense and a reduction in EKPC's base revenue requirement by $660,662 is reasonable

and should be accepted because EKPC has not provided sufficient evidence that ratepayer-provided dues are not used for legislative advocacy, regulatory advocacy, and/or public relations, which do not directly benefit ratepayers. While EKPC argued that only ten percent of the dues are unrecoverable, that amount is an estimate, and EKPC has not provided sufficient evidence that only ten percent of the membership dues relate solely to lobbying. Depreciation Rates - Depreciation and Amortization Expense Along with its initial application for approval of a general adjustment of rates, EKPC also proposed a new, revised depreciation study for all assets associated with its

Case No. 2025-00122, Electronic Application of Kentucky-American Water Company for an 127Adjustment of Rates (Ky. PSC Dec. 16, 2025), Order at 31-32; Case No. 2024-00276, Electronic Application of Atmos Energy Corporation for an Adjustment of Rates, Approval of Tariff Revisions, and Other General Relief (Ky. PSC Aug. 11, 2025), Order at 17.

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operations to be accepted by the Commission. Further, in its application, EKPC noted 128 that the proposed depreciation study incorporated interim and terminal net salvage components into depreciation rates, which EKPC believed was the approach that best aligned recovery through depreciation expense with those benefitting from the generating plants while in service. EKPC further noted that the incorporation of interim and 129 terminal net salvage was consistent with its current practice. 130 In this proceeding, EKPC hired Gannett Fleming Valuation and Rate Consultants, LLC (Gannett Fleming) to perform the depreciation study, related to the electric plant which was conducted as of December 31, 2023. Gannett Fleming performed the 131 depreciation study by using the straight-line remaining life method of depreciation, with the average service life procedure for all plant assets except certain general plant accounts. For General Plant accounts 391.00, 391.10, 393.00, 394.00, 395.00, 132 397.00, and 398.00, Gannett Fleming utilized the straight line remaining life method of amortization, as these General Plant accounts contain a large number of units with small asset values, and periodic inventories were required to properly reflect plant in service. 133

EKPC's accounting policy has not changed since its last depreciation study was

prepared. However, Gannett Fleming stated that there have been changes in plans of 134

Application at 10; Application, Volume 2, Exhibit 19, Attachment JJS-1. 128 Application at 10. 129 Application at 10. 130 Application, Volume 2, Exhibit 19, Attachment JJS-1, Executive Summary. 131 Application, Volume 2, Exhibit 19, Direct Testimony of John J. Spanos (Spanos Direct 132Testimony) (filed Aug. 1, 2025) at 4. Spanos Direct Testimony at 4. 133 Application, Volume 2, Exhibit 19, Attachment JJS-1, Executive Summary. 134

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some generating assets since the most recent study, as well as additions of capital investment in all plant categories. These additions were normalized through the June 135 30, 2024, to ensure the depreciation expense matched the updated plant in service balances used for the overall revenue requirement. Throughout the pendency of this 136 case, the Attorney General/Nucor took issue with the depreciation rates and useful lifespans proposed as a result of the depreciation study. Specifically, the Attorney 137

General/Nucor took issue with the inclusion of terminal net salvage in EKPC's

depreciation rates, the inclusion of estimated interim retirements and estimated interim

net salvage in EKPC's depreciation rates, and the estimated useful lifespans of EKPC's

generating units. However, the Attorney General/Nucor did not provide testimony on 138 the issue of the straight-line remaining life method of depreciation, with the average service life procedure. As a result of the aforementioned depreciation study, EKPC proposed an $8,309,434 pro forma adjustment to increase its Depreciation and Amortization Expense to arrive at a normalized test-year level of Depreciation and Amortization Expense of $95,691,393. EKPC stated that this test year level of Depreciation and Amortization 139

Application, Volume 2, Exhibit 19, Attachment JJS-1, Executive Summary. 135 EKPC's Response to AG-Nucor's Second Request for Information, Item 2. 136 Kollen Direct Testimony at 13, 17, and 23. 137 Kollen Direct Testimony at 13, 17, and 23. 138 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Ex 1 Adjust-Rev Inc Tab, 139Line 36.

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Expense also necessarily reflects the removal of depreciation expense recovered through the Environmental Surcharge. 140 Interim Retirements/Interim Net Salvage As mentioned above, prior to the Joint Settlement, the Attorney General/Nucor recommended the Commission exclude estimated interim retirements and estimated interim net negative salvage from the calculation of the production plant depreciation rates and depreciation expense. The Attorney General/Nucor argued that it was 141 unreasonable to unnecessarily and prematurely recover costs that have not yet been incurred, which would result in an ongoing cycle of excessive depreciation rates, excess depreciation expense, and excessive rates to customers. 142 stated that EKPC would be entitled to full recovery of its actual costs and would receive full recovery of these costs without unnecessarily and unreasonably harming customers by accelerating recovery through the use of estimated future costs before they are incurred. Lastly, the Attorney General/Nucor argued that the exclusion of the estimated 143 future costs simplified the development and improved the accuracy of the depreciation

rates by completely avoiding the need to develop "guestimates" of future interim

retirements and future interim net negative salvage. In rebuttal, EKPC argued that the 144

Intervenors' proposal to exclude these estimates was misleading because it characterized

interim retirements and net salvage as speculative future components rather than figures

Watson Direct Testimony at 21. 140 Kollen Direct Testimony at 22. 141 Kollen Direct Testimony at 21. 142 Kollen Direct Testimony at 22. 143 Kollen Direct Testimony at 22. 144

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grounded in actual, historical data. To support this, EKPC provided statistical evidence 145 showing that it experienced $122,322,934 in retirements over an 18-year period (2006- 2023), a figure that included $32,050,028 in cost of removal and $7,849,317 in gross salvage. EKPC further asserted that removing these estimates would suggest that 146 annual retirements and their associated removal costs would suddenly cease, an outcome its expert described as an unprecedented and unrealistic change for the standard operation of a generating facility. 147 Estimated Lifespans As mentioned above, prior to the Joint Settlement, the Attorney General/Nucor recommended the Commission modify and extend the estimated life span for all of the

units at EKPC's J.K. Smith Station (Smith Units) to 45 years in addition to modifying and

extending the estimated life span for all Hugh L. Spurlock Station (Spurlock Units) to 62 years. The Attorney General/Nucor stated this would extend the depreciable lives of 148 Smith Units 1, 2, and 3 by eight years, the depreciable lives of Smith Units 4, 5, 6, 7, 8, 9, and 10 by five years, the depreciable life of Spurlock Unit 2 by two years, the depreciable life of Spurlock Unit 3 by 18 years, and the depreciable life of Spurlock Unit 4 by 22 years. In rebuttal, EKPC argued that the Attorney General/Nucor's 149

Spanos Rebuttal Testimony at 13. 145 Spanos Rebuttal Testimony at 12, citing Application, Volume 2, Exhibit 19, Attachment JJS-1 at 146146. Spanos Rebuttal Testimony at 12. 147 Kollen Direct Testimony at 27. 148 Kollen Direct Testimony at 27. 149

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recommendation did not consider the appropriate life cycle of each generating unit. 150 For example, EKPC Witness Spanos, stated that for gas turbines, the most common life span is 40 years; coal-fired generating units built prior to 1980 generally have life spans between 55 and 65 years; and coal-fired generating units built after 1980 have an average estimated life span of less than 50 years, driven by economics and environmental regulations. EKPC further argued that the Attorney General/Nucor provided no 151 substantial basis for its proposal of extending life spans. 152 The Joint Settlement revenue requirement did not contain an adjustment to remove estimated interim retirements and estimated interim net salvage, nor did it contain an

adjustment related to extending the lifespans of EKPC's Smith and Spurlock Units. Thus, the Joint Settlement adopted EKPC's estimated life spans for its generation assets as

filed in the depreciation study. However, the Joint Settlement did contain an 153

adjustment relating to the removal of terminal net salvage from EKPC's depreciation

rates, as further discussed below.

Commission finds that, consistent with the Joint Settlement, the proposed depreciation study should be accepted as filed, outside of the adjustment to remove terminal net salvage from EKPC's thermal generating units as further discussed below. With respect

to the Attorney General/Nucor's recommended adjustment to remove the estimated

Spanos Rebuttal Testimony at 2. 150 Spanos Rebuttal Testimony at 2-3. 151 Spanos Rebuttal Testimony at 3. 152

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interim retirements and estimated interim net negative salvage, the Commission finds that

this adjustment would result in intergenerational inequity, mismatching the assets' costs

to the customers who pay for such costs. With respect to the Attorney General/Nucor's

recommended adjustment to extend the estimated useful lives of EKPC's Smith Units and Spurlock Units, the Commission finds that EKPC's depreciation study must allow for each unit's lifespan to be examined on its own basis, rather than grouping similar assets.

Depreciation Expense - Terminal Net Salvage As mentioned above, in its application, EKPC proposed a new, revised depreciation study to be approved by the Commission, inclusive of both terminal net salvage and interim net salvage components in its production plant depreciation rates. 154 The Attorney General/Nucor calculated the amounts of terminal net salvage that EKPC included in its production plant depreciation rates and recommended removing

$2,533,261 from EKPC's as-filed depreciation expense to account for terminal net

salvage for production plant accounts in which retirement had not yet been approved by the Commission. Prior to the Joint Settlement, the Attorney General/Nucor argued that 155 KRS 278.264 precluded recovery of decommissioning expense prior to seeking and obtaining Commission approval to retire a specific thermal generating unit. The 156 Attorney General/Nucor argued that EKPC had not filed an application to obtain approval to retire a specific thermal generating unit pursuant to the requirements set forth in

Application at 10. 154 Attorney General/Nucor's Workpapers, Depr Summary Adj 1,2 and 3 Tab, Cell W263. 155 Kollen Direct Testimony at 16. 156

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KRS 278.264(2). Arguably, KRS 278.264(2) precludes recovery of decommissioning 157 costs until after the utility files an application, and the Commission approves the retirement of the specific thermal generating unit. Additionally, the Attorney 158 General/Nucor argued that, even without KRS 278.264, the decommissioning expense should not be recovered prior to retirement because the decommissioning costs are inherently not known or measurable. The Attorney General/Nucor recommended the 159

Commission deny recovery of the decommissioning expense for EKPC's thermal

generating units arguing it was prohibited by KRS 278.264, was unnecessary, resulted in a permanent cost penalty to customers, and the delayed recovery of these costs promotes intergenerational equity among customers. As a result, the Attorney 160 General/Nucor proposed a $2,533,261 reduction in depreciation expense which resulted in a $2,537,197 reduction in the base revenue requirement. 161

In rebuttal, EKPC argued that the Attorney General/Nucor's proposal to remove

terminal net salvage to the date of retirement would result in insufficient recovery of

EKPC's actual costs. According to EKPC, it is widely accepted that depreciation should 162 include future net salvage costs and that these costs should be based on the expected

Kollen Direct Testimony at 16. 157 See Case No. 2024-00354, Electronic Application of Duke Energy Kentucky, Inc. For: 1) An 158 Adjustment of the Electric Rates; 2) Approval of New Tariffs; 3) Approval of Accounting Practices to Establish Regulatory Assets and Liabilities; and 4) All Other Required Approvals and Relief (Ky. PSC Oct. 2, 2025), Order at 40-41. Kollen Direct Testimony at 16. 159 Kollen Direct Testimony at 17. 160 Kollen Direct Testimony at 17, Attorney General/Nucor's Workpapers, Depr Summary Adj 1,2 161and 3 Tab, Cell W263. Spanos Rebuttal Testimony at 5-6. 162

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cost to retire the Company's assets at the time of retirement or removal. To further 163 argue this point, EKPC cited to the National Association of Regulatory Utility

Commissioners' (NARUC) Public Utility Depreciation Practices, which states that the goal

of accounting for net salvage is to allocate the net cost of an asset to accounting periods, making due allowance for the net salvage, positive or negative, that will be obtained when the asset is retired. 164 As part of the Joint Settlement, the Parties agreed to remove terminal net salvage

expenses from EKPC's thermal generating units in the amount of $2,559,120. 165

Commission finds that the Joint Settlement adjustment relating to the removal of terminal

net salvage from EKPC's thermal generating units is reasonable and should be accepted,

consistent with the requirements set forth in KRS 278.264(2) and prior Commission treatment of terminal net salvage for thermal generating units. EKPC has the burden 166 to overcome the presumption established in KRS 278.264, and EKPC has not presented sufficient evidence in this matter to meet that burden. Therefore, the Commission may

Spanos Rebuttal Testimony at 5-6. 163 Spanos Rebuttal Testimony at 8 citing the NARUC Public Utilities Depreciation Manual at 18. 164 Joint Settlement, Exhibit A. 165 See Case No. 2017-00321, Electronic Application of Duke Energy Kentucky, Inc. for: (1) an 166 Adjustment of Electric Rates; (2) Approval of an Environmental Compliance Plan and Surcharge Mechanism; (3) Approval of New Tariffs; (4) Approval of Accounting Practices to Establish Regulatory Assets and Liabilities; and (5) all Other Required Approvals and Tariff (Ky. PSC Apr. 13, 2018), Order at 27; Case No. 2022-00372, Electronic Application of Duke Energy Kentucky, Inc. for (1) An Adjustment of the Electric Rates; (2) Approval of New Tariffs; (3) Approval of Accounting Practices to Establish Regulatory Assets and Liabilities; and (4) All Other Required Approvals and Relief (Ky. PSC Oct 12, 2023), Order at 14; Case No. 2024-00354, Electronic Application of Duke Energy Kentucky, Inc. For: 1) An Adjustment of the Electric Rates; 2) Approval of New Tariffs; 3) Approval of Accounting Practices to Establish Regulatory Assets and Liabilities; and 4) All Other Required Approvals and Relief (Ky. PSC Oct. 2, 2025), Order at 40-

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not allow recovery of costs for the retirement of thermal electric generating units, except for those it has already received Commission approval to retire. Removing terminal net

salvage from EKPC's thermal generating units reduces its test-year depreciation expense by $2,559,120 and reduces EKPC's base revenue requirement by $2,563,097.

Outage Insurance Payments In its application, EKPC proposed an adjustment to remove insurance payouts in the amount of $4,691,458, as these were non-recurring revenues. 167 168 it secured outage insurance in 2022, to cover potential forced outage-related costs. 169 EKPC stated that it submitted claims during Winter Storm Elliot for these outage-related costs and the funds were disbursed in 2023. EKPC stated that the test year outage 170 insurance revenue should have been reported as $4,666,981 rather than $4,691,458 in the application. EKPC stated that proceeds of $24,477 from a workers' compensation 171 claim were inadvertently included as outage insurance on Schedule 1.19. However, in 172 rebuttal, EKPC stated that it has no guarantee that it will collect this revenue every year and would only collect this revenue when it has a corresponding expense. 173 174

Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.19. 167 Watson Direct Testimony at 22. 168 Watson Direct Testimony at 21. 169 Watson Direct Testimony at 21-22. 170 EKPC's Response to the Attorney General/Nucor's Second Request, Item 8; Application, Exhibit 17116, Attachment JRW-1, Statement of Operations, Schedule 1.19. EKPC's Response to the Attorney General/Nucor's Second Request, Item 8. 172

173 174

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Prior to the Joint Settlement, the Attorney General/Nucor recommended the Commission correct the error in the pro forma adjustment amount resulting in an increase of $24,777 to EKPC's Other Non-Operating Income and a reduction to the revenue requirement by $24,815. 175 The Joint Settlement included EKPC's adjustment removing insurance payouts attributed to Winter Storm Elliot as filed. The Joint Settlement did not include the Attorney

General/Nucor's recommended adjustment.

The Commission finds that EKPC's proposed adjustment of $4,691,458 is 176 reasonable and should be accepted because the payments are non-recurring in nature and these proceeds are irregular offsets to extraordinary expenses such as those from Winter Storm Elliott and do not represent a stable or predictable source of annual income. Consistent with the Joint Settlement, the Commission finds that the Attorney

General/Nucor's proposed adjustment of $24,477 to remove payments associated with

workers' compensation claims should be rejected because, like the outage insurance, these claims are contingent upon specific, non-routine incidents and do not occur in a manner that warrants normalization for ratemaking purposes. Accepting EKPC's pro- forma adjustment to remove outage insurance payouts as filed increases EKPC's base revenue requirement by $4,698,749.

Futral Direct Testimony at 13. 175 The Commission notes that while the amounts related to worker's compensation claims should 176not have been included in this particular schedule relating to forced outage insurance claims, revenues

gained from worker's compensation claims do not represent a stable source of income for EKPC and thus,

do not warrant normalization for ratemaking purposes.

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Rate Case Expense In its application, EKPC proposed a total Rate Case Expense of $650,000 amortized over three years for $216,667 per year. EKPC was directed to file monthly 177 updates to its Rate Case Expense with invoices, with the last update filed on January 178 9, 2026. In its final monthly Rate Case Expense update, EKPC provided its actual total 179 Rate Case Expense of $547,710 which, amortized over three years, is $182,570 per year. 180 In the Joint Settlement, the Parties agreed that EKPC should be authorized to recover its actual, reasonable rate case expense, including the amounts for its Owner-

Members' pass-through cases on an amortized basis over three years. 181 The Commission finds that, based on the updates provided throughout the pendency of this case and a review of the supporting invoices, the updated actual rate case expense for the current proceeding is reasonable. Therefore, the Commission finds

that EKPC's Rate Case Expense should be reduced to $547,710 and approves the

recovery of $182,570 over a three-year period, consistent with the Joint Settlement and historical regulatory practice. This adjustment reduces EKPC's proposed total Rate Case Expense by $102,290 or $34,097 per year and reduces EKPC's proposed base revenue requirement by $34,150 after the gross-up for PSC Assessment fees.

Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.23. 177 Commission Staff's First Request, Item 35c. 178 EKPC's Supplemental Response to Staff's Post-Hearing Request, Item 2 and 3. 179 EKPC's Supplemental Response to Staff's Post-Hearing Request, Item 2 and 3. 180

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Deferred Prior Rate Case Expense Prior to the Joint Settlement, the Attorney General/Nucor recommended that the Commission remove amortization expense in the amount of $247,498 associated with 182 the deferred rate case expenditures from Case No. 2021-00103 (Deferred Prior Rate Case Expense), since those costs were already fully amortized and recovered from ratepayers. The Attorney General/Nucor pointed out that EKPC's base rate case 183 expense from Case No 2021-00103 was fully amortized in September 2024 and recovered costs will continue in base rates until rates are reset in this proceeding. 184 EKPC stated that the deferred costs were being amortized at the rate of $20,625 each month. The Attorney General/Nucor also noted that EKPC confirmed that it made 185 no pro forma adjustment to remove the associated amortization expense from the test year. The Attorney General/Nucor argued that EKPC's amortization expense should 186 be reduced by $247,498 for the prior rate case deferred costs, which would result in a reduction in the base revenue requirement and requested base rate increase of $247,882 after the gross-up for the PSC assessment fees. 187 In the Joint Settlement, the Parties agreed to include the removal of Deferred Rate Case Expense in the amount of $20,625 per month which results in a total reduction of $247,498.

Joint Settlement, Exhibit A; Watson Settlement Testimony at 4. 182 Futral Direct Testimony at 14. 183 Futral Direct Testimony at 13. 184 EKPC Responses to Attorney General/Nucor's Second Request, Item 9(a). 185 Futral Direct Testimony at 13. 186 Futral Direct Testimony at 14. 187

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Consistent with the Joint Settlement, the Commission finds that the $247,498 reduction to remove the Deferred Rate Case Expense is reasonable and should be accepted, as it ensures that EKPC will not over-recover any of its historical costs associated with its prior base rate case. The Commission further finds that this adjustment is reasonable on the basis that these costs were fully amortized as of September 2024, and including these deferred costs in the revenue requirement in this proceeding would allow EKPC to over-collect revenue from its customers as soon as new rates were put into effect, regardless of the time between the instant proceeding and when EKPC anticipates filing its next base rate case. Amortization of Generation Maintenance Regulatory Asset EKPC proposed to amortize its Generation Maintenance Regulatory Asset balance of $27,498,249 over three years, which totaled $9,166,083 per year. This included a 188 beginning test period balance of $9,233,640. EKPC was ordered to file for recovery of 189 the amortization of the net accumulated balance in its next rate case. The proposed 190 adjustment reflected the current accumulated balance and EKPC's proposed amortization period of three years for the accumulated balance. 191 In the Joint Settlement, the Parties agreed to amortize the $27,498,249 over six years, resulting in $4,583,042 per year. 192

Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.26. 188 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.26. 189

190 191

Watson Direct Testimony at 25. 192

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The Commission finds that the Parties' agreement to amortize the $27,498,249 Generation Maintenance Regulatory Asset over six years, rather than three, is reasonable and should be approved as it serves to mitigate the immediate rate impact on customers while ensuring the cooperative's recovery of these deferred costs on a timeframe in line with the maximum stay-out provision in the Joint Settlement. This adjustment reduces

EKPC's as-filed Amortization of Generation Maintenance Regulatory Asset adjustment

by $4,583,041, and reduces EKPC's revenue requirement by $4,590,163. Generation Maintenance Threshold Amount Time Period

In EKPC's prior rate case, Case No. 2021-00103, the Commission approved a

Generation Maintenance Tracker which included a Generation Maintenance Regulatory Asset Threshold (Generation Maintenance Threshold) in the amount of $81,067,000 based on normalized Generation Maintenance Expense over a five-year period of 2015 through 2019. In Case No. 2022-00430, the Generation Maintenance Threshold was 193

reduced to $63,842,645 to exclude the amount that was recovered through EKPC's

ES. 194195

Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.27; Case No. 1932021-00103, Sept. 30, 2021 Order at 24. Case No. 2022-00430, Electronic Application of East Kentucky Power Cooperative, Inc. To 194 Amend the Joint Stipulation and Settlement Agreement and The Commission's Final Order in Case No. 2021-00103 (Ky. PSC Jan. 27, 2023), Order; Case No. 2022-00430, Dec. 27, 2022 Application, Exhibit ISS-1. The Commission notes that in Case No. 2022-00430, filed Dec. 27, 2022, Application at 5 and 195Footnote 2, EKPC referred to the Generation Maintenance Threshold as "the 2016-2020 threshold" and explained that the Generation Maintenance Threshold in the amount of $81.067 million was determined using Case No. 2021-00103, filed June 4, 2021, EKPC's Response to the Supplemental Data Requests of the Attorney General and Nucor, Request 19a, at 6-8. As such, the Commission assumes any reference to a Generation Maintenance Threshold based on an average of Generation Maintenance Expense for the years 2015 through 2019 in this proceeding to mean the updated Generation Maintenance Threshold approved in Case No. 2022-00430 based on an average of Generation Maintenance Expense for the years 2016 through 2020.

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EKPC proposed to update the normalized threshold on its Generation Maintenance Tracker based on a four-year average of Generation Maintenance Expense from 2020 through 2023. EKPC utilized this proposed threshold to calculate the 196 amount proposed to be included in base rates. In addition, EKPC proposed to use this 197 new Generation Maintenance Threshold for future excess generation maintenance expenses that flow into the Generator Maintenance Tracker. EKPC stated that any 198 difference above or below the Generation Maintenance Threshold based on recorded costs was tracked, and EKPC recorded 75 percent of the difference in a regulatory asset. The new proposed Generation Maintenance Threshold based on a four year 199 average of Generation Maintenance Expense was in the amount of $77,006,390. 200 EKPC argued that since the establishment of the Generation Maintenance Tracker, its costs have increased substantially compared to the current Generation Maintenance Threshold due to inflation and equipment cost increases. 201 Prior to the Joint Settlement, the Attorney General/Nucor argued that there was no reason to reduce the time period, to only four years of Generation Maintenance Expense, used to calculate the average historic expense threshold level. 202 General/Nucor argued that a longer expense period more effectively spreads the risks

Watson Direct Testimony at 25. 196 Watson Direct Testimony at 25. 197 Watson Direct Testimony at 25. 198

Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.27. 200 Watson Direct Testimony at 25. 201 Futral Direct Testimony at 10. 202

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associated due to the cyclical nature, timing, and scope of major generation outages and the related maintenance expense. The Attorney General/Nucor recommended that the 203 Commission base the Generation Maintenance Threshold in the test year upon the average expense amount over the five year period of 2020 through 2024. 204 The Commission finds that the Parties' agreed upon adjustment to EKPC's Generation Maintenance Threshold to base the threshold on a five-year average of Generation Maintenance Expense for the years 2020 through 2024 as set forth in the Joint Settlement is reasonable. The Commission is persuaded by the Attorney

General/Nucor's argument regarding the benefits of longer expense periods including the

suggestion to base the average used in setting base rates on a longer time period, which would likely have the effect of reducing volatility and smoothing variances that may be specific to a given year. Therefore, the Commission finds that determining the Generation Maintenance Threshold by utilizing an average of the most recent five calendar years prior to the filing of the Application is reasonable and appropriate. Generation Maintenance Threshold Adjustments in Test Period EKPC proposed an adjustment for additional recoverable expense of $3,290,936 as a result of revising the Generation Maintenance Threshold amount. Prior to the 205 Joint Settlement, the Attorney General/Nucor argued that EKPC incorporated an error when setting the Generation Maintenance Threshold. According to Attorney 206

Futral Direct Testimony at 10. 203 Futral Direct Testimony at 11. 204 Application, Exhibit 16, Attachment JRW-1, Statement of Operations, Schedule 1.27. 205 Futral Direct Testimony at 7. 206

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General/Nucor, the test year level of expense proposed to be included base rates should match the threshold level of expense for the Generation Maintenance Tracker to work as intended, and that, based on the use of a four-year average of Generation Maintenance

Expense from 2020 through 2023 as proposed by EKPC, the amount of EKPC's error

amounted to $9,872,809 in reduced Generation Maintenance Expense to its detriment. 207

The Attorney General/Nucor recommended that the Commission correct EKPC's

methodology errors and increase the threshold generation maintenance expense included in the test year. Additionally, the Attorney General/Nucor argued that the use 208 of the five-year average resulted in a decrease in the test year expense by $2,367,854

after correction of EKPC's methodology error. The total of the Attorney 209

General/Nucor's recommendations to Generation Maintenance Expense resulted in EKPC's test year Generation Maintenance Expense increasing by $7,504,955 which then

resulted in an increase in the base revenue requirement and requested base rate increase of $7,516,617 after the gross-up for PCS assessment fees. 210 In the Rebuttal testimony, EKPC agreed that updating the adjustment to a five- year average of the years 2020 through 2024 increased the baseline revenue requirement by $7,516,617 and recommended the Commission accept the proposed increase. 211 However, in response to post-hearing discovery, EKPC stated that it disagreed with a

portion of the Attorney General/Nucor's calculation of their correction to EKPC's

Futral Direct Testimony at 10-11. 207 Futral Direct Testimony at 11. 208 Futral Direct Testimony at 11. 209 Futral Direct Testimony at 12. 210 Watson Rebuttal Testimony at 5-6. 211

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Generation Maintenance Threshold calculation which would have resulted in an increase

to EKPC's requested revenue by $9,872,809. EKPC argued that the Attorney 212

General/Nucor's calculation mistakenly included the existing Generation Maintenance

regulatory asset that EKPC proposed to amortize in this case. 213 The effect of setting the Generation Maintenance Threshold based on a five-year historical average from 2020 through 2024, as agreed upon in the Joint Settlement, is a

reduction to EKPC's revenue requirement of $2,367,854. The Joint Settlement did not 214

include the Attorney General/Nucor's proposed adjustment to correct EKPC's

calculation. EKPC stated that, had EKPC agreed to the Attorney General/Nucor's 215 calculation, it would be double recovering the Generation Maintenance regulatory asset through its base rates, and that the correct Generation Maintenance adjustment was included in the Joint Settlement. 216

The Commission finds that EKPC's Generation Maintenance Threshold

adjustment should be reduced by $2,367,854, consistent with the Joint Settlement. The effect of this adjustment to the Generation Maintenance Threshold is a reduction to

EKPC's revenue requirement of $2,371,534.

Amortization Expense for Deferred Smith 1 and Deferred 2019 Spurlock Prior to the Joint Settlement, the Attorney General/Nucor recommended EKPC's as-filed Amortization Expense be reduced by a total of $9,001,694, resulting in a reduction

EKPC's Response to Staff's Post-Hearing Request, Item 18. 212 EKPC's Response to Staff's Post-Hearing Request, Item 18. 213

EKPC's Response to Staff's Post-Hearing Request, Item 18. 215 EKPC's Response to Staff's Post-Hearing Request, Item 18. 216

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to the base revenue requirement and requested base rate increase of $9,015,683 after gross-up for PSC assessment fees. The Attorney General/Nucor's proposed reduction 217 was based on two adjustments to reset the amortization periods for unamortized 218 deferred costs to three years. 219 The Attorney General/Nucor proposed to reduce Amortization Expense for Deferred 2019 Spurlock by $427,608. The Attorney General/Nucor argued that the 220 Deferred 2019 Spurlock expenses from Case No. 2021-00103 would be fully amortized 221 in December 2027, 19 months after rates are expected to go into effect resulting from this proceeding. In Case No. 2021-00103, the Commission authorized an eight year 222 amortization period of the original deferred costs totaling $7,244,184. As a result of 223 Case No. 2021-00103, the 2023 test year Amortization Expense was $905,523 with an 224 unamortized balance of $2,188,347 at the end of July 2025, being amortized at the rate of $75,460 each month. The Attorney General/Nucor stated that the unamortized 225

Futral Direct Testimony at 17. 217 One adjustment to reduce Amortization Expense for deferred Smith 1 cancelation costs 218(Deferred Smith 1) and one adjustment to reduce Amortization Expense for 2019 deferred major maintenance expenses at the Spurlock generating station (Deferred 2019 Spurlock) which will both be discussed in this section. Futral Direct Testimony at 14-15. 219 Futral Direct Testimony at 17 and Attorney General/Nucor's Workpapers, Deferred Cost 220Amortization Tab, Line 39. Case No. 2021-00103, Sept. 30, 2021 Order at 18. 221 Futral Direct Testimony at 15. 222 Case No. 2021-00103, Sept. 30, 2021 Order at 18-20. 223 7,244,184 / 8 years = 905,523. 224 Futral Direct Testimony at 15-16. 225

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balance would be $1,433,744 at the end of May 2026. 226 argued that, if the Commission includes the current monthly $75,460 in Amortization Expense in the revenue requirement and EKPC's base rates are not reset again until June 1, 2029, assuming three years between rate cases, then EKPC would over-recover costs of $1,282,824, with an over-recovery even higher if the time between rate cases exceeded three years. Therefore, the Attorney General/Nucor recommended that the 227 Commission reset the amortization period for the unamortized Deferred 2019 Spurlock costs to three years, and that the Amortization Expense be based on the unamortized balance as of May 31, 2026, assuming a rate increase effective date from this proceeding of June 1, 2026. 228 In rebuttal, EKPC stated that the Commission initially approved the deferral of the Deferred 2019 Spurlock costs in Case No. 2021-00103 to be fully amortized in December 2027, and EKPC did not believe the amortization expense should be removed from 229 revenue requirement or adjusted until it has been fully amortized. EKPC argued that 230 extending the amortization period would likely place EKPC in the same situation in its next rate case, where a balance was remaining to be amortized. EKPC recommended 231 that the Attorney General/Nucor's adjustment be rejected. 232

Futral Direct Testimony at 16. 226 Futral Direct Testimony at 16. 227 Futral Direct Testimony at 16. 228 Case No. 2021-00103, Sept. 30, 2021 Order at 38. 229 Watson Rebuttal Testimony at 7. 230 Watson Rebuttal Testimony at 7. 231 Watson Rebuttal Testimony at 7. 232

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The amortization expense for Deferred 2019 Spurlock was not addressed in the Joint Settlement. However, during the hearing, EKPC witness Watson testified that, as a result of the Joint Settlement, EKPC would be withdrawing its request for the Generation Maintenance Tracker, resulting in EKPC only recovering the unamortized balances of the regulatory assets that are currently on its books. Therefore, Watson stated that EKPC 233 would not continue to book these costs as a regulatory asset moving forward. 234

The Commission finds that the amortization period for EKPC's Deferred 2019

Spurlock costs should not be reset and should be accepted as filed. However, the Commission notes that its approval of the continuation of the Generation Maintenance Tracker will result in EKPC continuing to book costs similar to the Deferred Spurlock 2019 maintenance costs as a regulatory asset. The second adjustment by the Attorney General/Nucor was to reduce the Amortization Expense for Deferred Smith 1 by $8,574,086. 235

General/Nucor argued that EKPC's Deferred Smith 1 costs from Case Nos. 2010-

00449 and 2015-00358 would be fully amortized in December 2026, seven months 236 237 after rates are expected to go into effect resulting from this proceeding. 238

HVT of the Dec. 8, 2025 Hearing, Hearing Testimony of Jacob Watson at 04:56:27-04:56:52. 233 HVT of the Dec. 8, 2025 Hearing, Hearing Testimony of Jacob Watson at 04:56:27-04:56:52. 234 Futral Direct Testimony at 17; Attorney General/Nucor's Workpapers, Deferred Cost 235Amortization Tab, Line 39. Case No. 2010-00449, Application of East Kentucky Power Cooperative, Inc. for an Order 236 Approving the Establishment of a Regulatory Asset for the Amount Expended on its Smith 1 Generating Unit. Case No. 2015-00358, Application of East Kentucky Power Cooperative, Inc. for Deviation from 237Obligation Resulting from Case No. 2012-0169. Futral Direct Testimony at 14-15. 238

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General/Nucor noted that the Deferred Smith 1 unamortized balance at the end of July 2025 was $15,078,566, and was being amortized at the rate of $886,974 each month resulting in the test year Amortization Expense of $10,643,693. 239 General/Nucor argued that, if the Commission included the current $886,974 per month

in Amortization Expense in the revenue requirement and EKPC's base rates were not

reset again until June 1, 2029, assuming three years between rate cases, then EKPC would over-recover costs of $25,722,260. The Attorney General/Nucor noted that the 240 over-recovery would be even higher if the time between rate cases exceeded three years and such an over-recovery would be inappropriate. Therefore, the Attorney 241 General/Nucor recommended that the Commission reset the amortization period for the unamortized Deferred Smith 1 costs to three years, and that the Amortization Expense be based on the unamortized balance as of May 31, 2026, assuming a rate increase effective date from this proceeding of June 1, 2026. 242 In rebuttal, EKPC stated the Commission initially approved the deferral of the Smith 1 Cancellation Costs in Case No. 2010-00409. EKPC further stated that in Case 243 No. 2015-00358, the Commission allowed EKPC to amortize the Smith 1 regulatory asset over 10 years to be fully amortized in January 2027. EKPC recommended that the 244

Futral Direct Testimony at 15 and Attorney General/Nucor's Workpapers, Deferred Cost 239Amortization Tab, Line 37. Futral Direct Testimony at 15; 886,974.49 * 29 months = $25,722,260.21. 240 Futral Direct Testimony at 15. 241 Futral Direct Testimony at 16. 242

243 244

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Attorney General/Nucor's adjustment to remove the Deferred Smith 1 cancellation costs

from the revenue requirement be rejected on the grounds that extending the amortization period would likely place EKPC in the same situation in its next rate case, where a balance is remaining to be amortized. 245 In the Joint Settlement, the Parties agreed to extend the amortization period for the Deferred Smith 1 cancellation costs by six years starting May 2026, to align with

EKPC's maximum stay-out provision. 246

Commission finds that the amortization period for EKPC's Deferred Smith 1 cancellation

costs should be reset for the remaining balance to be fully amortized by January 31, 2030, approximately 13 years from the start of the Deferred Smith 1 amortization. This

adjustment to reset the amortization period of EKPC's Deferred Smith 1 regulatory asset reduces EKPC's as-filed Amortization Expense by $8,950,379 and reduces EKPC's base

revenue requirement by $8,964,288. The Commission has expressed EKPC's unique position as a G&T Cooperative with regard to regulatory assets, as well as reaffirmed 247 the terms outlined for the Deferred Smith 1 regulatory asset specifically when the amortization period was originally determined as a result of a settlement agreement. 248

Watson Settlement Testimony at 6. 246 Case No. 2025-00193, Electronic Application of East Kentucky Power Cooperative, Inc. For an 247 Order Approving the Establishment of a Regulatory Asset for The Expenses Associated with The Regional Sept. 29, 2025), Order at 10. Case No. 2021-00103, Electronic Application of East Kentucky Power Cooperative, Inc. For a 248 and Other General Relief (Ky. PSC Sept. 30, 2021), Order at 12-16.

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The proposed adjustment to reset the amortization period for the remaining balance of the Deferred Smith 1 regulatory asset in this proceeding was also the result of a Joint Settlement and, therefore, the Commission makes this finding to reset the amortization period solely for the purpose of setting the revenue requirement as close to the agreed amount set by the parties in the Joint Settlement. The Commission notes that this finding is not to be used as precedent in future cases and is only being done as a result of the Joint Settlement. The Commission has concerns with re-amortizing balances over longer periods from case to case and Parties recommending re-amortization as a method for lowering the revenue requirement. The Commission understands the basis of the stipulated six-year amortization periods to be consistent with the maximum stay-out provision agreed upon in the Joint Settlement. However, the Commission is concerned about the effect of extending amortization periods of deferred costs originally presented as long ago as 2010 for an additional six years, and the possibility of the same issues being presented in future proceedings should EKPC request to adjust its rates prior to these expenses being fully amortized. The purpose of regulatory asset treatment is to allow for gradual recovery of extraordinary expenses, and the Commission recognizes that the amortization of deferred expenses will rarely match the exact timing of rate proceedings. Because EKPC has utilized a historical test period, it is appropriate to make a known adjustment to the test year expenses to recover the remaining balance of the deferred asset. RTEP Regulatory Asset Amortization. During the pendency of this case, the Commission approved a request from EKPC for authorization to establish regulatory assets for expenses associated with RTEP through December 31, 2025 (RTEP

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Regulatory Asset), in Case No. 2025-00193. In the Joint Settlement, EKPC proposed 249 to collect the costs associated with the RTEP Regulatory Asset over a six-year amortization period. EKPC stated that the amount authorized for the RTEP Regulatory 250 Asset, in excess of what EKPC is allowed to recover in base rates, would be $20,165,905 based on the most recent billing from PJM through October 2025, and that, if amortized over six years, the proposed adjustment would increase EKPC's proposed revenue requirement by $3,360,984. 251 The Commission finds that EKPC's proposed adjustment to collect the costs associated with the RTEP Regulatory Asset over a six-year amortization period is reasonable and should be approved. However, the Commission notes that EKPC's calculation of the RTEP Regulatory Asset in the amount of $20,165,905 is based on an annualization of actual RTEP expenses through May 2025, rather than October 2025 as the testimony suggests. 252 Therefore, the Commission finds that the RTEP Regulatory Asset should be reduced to reflect the annualization of actual RTEP expenses based on the most recent billing from PJM through October 2025, in the amount of $20,036,324. When amortized over a 253 six-year period, the Commission's adjustment results in an annual RTEP Regulatory

Case No. 2025-00193, Electronic Application of East Kentucky Power Cooperative, Inc. For An 249 Order Approving the Establishment of a Regulatory Asset for The Expenses Associated with The Regional Sept. 29, 2025), Order at 12. Watson Settlement Testimony at 7. 250 Watson Settlement Testimony at 7. 251 Joint Settlement, Exhibit A, Schedule 1.06. 252 Joint Settlement, Exhibit A, Schedule 1.06. 253

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Asset amount of $3,339,387, and an increase in the base revenue requirement and requested base rate increase of $3,344,577 after the gross-up for the PSC assessment fees, and reflects a reduction of $21,630 to the adjustment proposed in the Joint

Total Revenue Requirement Summary

The effect of the Commission's approved adjustments is a revenue requirement increase

of approximately $63,670,273, as shown in the table below. This reflects an approximate $17,414,336 reduction to EKPC's originally requested base revenue increase of $79,757,474.

EKPC Requested Rate Increase 79,757,474$

TIER Adjustments: EKPC requested a TIER of 1.50, which it stated is consistent with the TIER levels Lobbying Expense (660,662)

Depreciation Expense (2,563,097) Rate Case Expense (34,150) approved in prior EKPC base rate and environmental surcharge proceedings. EKPC 254Deferred Prior Rate Case Expense (247,883) Amortization of Generation Maintenance Regulatory Asset (4,590,164) Generation Maintenance Threshold (2,371,534) Amortization Expense -- Deferred Smith 1 (8,964,288) RTEP Regulatory Asset Amortization 3,344,577 Application, Exhibit 13, Direct Testimony of Cliff Scott Direct Testimony (Scott Direct Testimony) 254 (filed Aug. 1, 2025) at 6. Subtotal (16,087,201) Rate Increase 63,670,273$ -52- Case No. 2025-00208 EKPC 2023 Gross Operating Revenues 1,061,654,877$ Percent Rate Increase 6.00%

argued that the consequences of the Commission authorizing a TIER lower than 1.50 would likely include a downgrade by credit rating agencies and increase in interest rates. EKPC explained that it is able to seek a lower TIER than its Owner-Members 255 due to EKPC having less risk for lenders as a Generation and Transmission (G&T) cooperative. The Rural Utilities Service (RUS) requires that the minimum coverage 256 ratios for distribution borrowers are a TIER of 1.25 and a Debt Service Coverage Ratio (DSC) of 1.25, and the minimum coverage ratio for power supply borrowers are a TIER of 1.05 and DSC of 1.00. EKPC stated that, while a TIER higher than 1.50 would create 257 greater financial stability to protect EKPC against future financial uncertainty, maintaining a 1.50 TIER is reasonable, as it would permit EKPC to continue to satisfy future RUS requirements and maintain its financial stability without overburdening its Owner- Members and their retail customers. EKPC argued that maintaining a healthy credit 258 rating benefits both EKPC and its Owner-Members. 259 Additionally, EKPC argued that it must earn revenue sufficient to meet all operating and fixed costs with sufficient margin to allow debt investors to be comfortable that all debt obligations can be satisfied. EKPC explained that, without this assurance, its 260 ability to access debt becomes more costly, ultimately resulting in higher rates. Based 261

Scott Direct Testimony at 7. 255 Application, Exhibit 18, Direct Testimony of Thomas J. Stachnik (Stachnik Direct Testimony) 256(filed Aug. 1, 2025) at 12. Stachnik Direct Testimony at 12. 257 Stachnik Direct Testimony at 12. 258 Scott Direct Testimony at 7. 259 Stachnik Direct Testimony at 13. 260 Stachnik Direct Testimony at 13. 261

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on an analysis EKPC performed comparing itself to a proxy group of other G&T cooperatives, EKPC argued that its current TIER and DSC are lower than the group medians of 1.60 and 1.41, respectively. EKPC explained that the majority of its peers 262 are not rate-regulated and argued that, since EKPC cannot increase rates without seeking regulatory approval, it is prudent that a 1.50 target TIER be retained so that EKPC can maintain its favorable credit ratings. EKPC argued that its request to target a TIER of 263 1.50 is supported by peer comparisons and an analysis of its cost of capital, and would result in a reasonable return consistent with that of peers and would support EKPC's credit ratings, debt covenants, and financial strength. 264 The Attorney General/Nucor did not provide a recommendation on the TIER and calculated their recommended revenue increase based on the proposed TIER of 1.50. 265 In the Joint Settlement, the Parties agreed to a 1.50 TIER for base rates. 266 The Commission finds that a TIER of 1.50, as agreed to in the Joint Settlement, is reasonable and should be approved, as it reflects the lessened risk associated with EKPC being a G&T cooperative, while still providing reasonable contingency for EKPC to satisfy its debt requirements and maintain its credit rating, which is further discussed below.

Stachnik Direct Testimony at 13-14 and Application, Exhibit 18, Attachment TJS-2. 262 Stachnik Direct Testimony at 15-16. 263 Stachnik Direct Testimony at 20. 264 Futral Direct Testimony at 25: Attorney General/Nucor's Workpapers Revenue Requirement 265Tab and 1.30-As Filed and Adj Rev Inc Tab, Line 14. Joint Settlement at 2. 266

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CREDIT RATINGS EKPC stated it currently holds investment grade ratings of 'A (Stable Outlook)' by

Standard and Poor's (S&P) and 'BBB+ (Negative Outlook)' by Fitch Ratings (Fitch). 267 Since its late base rate case, EKPC stated that, while the credit ratings remain the same,

the Outlook on the Fitch rating was reduced to "Negative". The Fitch report stated that 268 the Negative Outlook reflects the projected weakening in the EKPC's leverage profile over the medium to long term as the utility undergoes an expanded capital expenditure (capex) plan over the next decade. The credit report from Fitch stated that "revision of the 269 Negative Outlook will depend on an increase in operating cash flow through rate

increases or reduced discretionary expenditures." EKPC explained that under EKPC's 270 Indenture, EKPC is required to be rated by two nationally recognized statistical rating

organizations, which includes S&P, Fitch, and Moody's. EKPC further explained that 271 holding these ratings is also essential in obtaining any financing from the capital markets. EKPC stated that EKPC's S&P rating directly affects the price EKPC pays in interest costs and undrawn fees on the credit facility. 272

Stachnik Direct Testimony at 3. 267 Stachnik Direct Testimony at 3. 268 Stachnik Direct Testimony at 3 and Application, Exhibit 18, Attachment TJS-4. 269 Stachnik Direct Testimony at 9. 270 Stachnik Direct Testimony at 9. 271 Stachnik Direct Testimony at 9. 272

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EARNINGS MECHANISM (EM) /SYMMETRICAL EARNINGS MECHANISM (SEM) In its application, EKPC proposed to remove the EM which was originally established in Case No. 2021-00103. EKPC explained that the EM proved 273 burdensome to implement, would continue to be burdensome in the future, and also

negatively impacts EKPC's ability to manage its finances. In Case No. 2021-00103, 274 the Parties (which included the Attorney General and Nucor) agreed to an earnings mechanism that would return excess margins to customers in the form of a bill credit, if EKPC achieved a per book margin in excess of 1.40 TIER in any calendar year. The 275 Commission, in that case, found the proposed EM was reasonable and should be approved. 276 Prior to the Joint Settlement, the Attorney General/Nucor argued that the EM provided EKPC and the Commission a practical regulatory tool to capture excess earnings as well as to manage the timing of expenses through delays or accelerations, but still allow EKPC to earn a TIER that is close to its allowed TIER, all else equal. The 277

Attorney General/Nucor recommended that the Commission deny EKPC's request to

terminate the EM. The Attorney General/Nucor stated that as a practical alternative to 278 retaining the EM, the EM could be transitioned to a deferral mechanism whereby excess

Application at 14. 273 Watson Direct Testimony at 29-30. 274 Case No. 2021-00103, Sept. 30, 2021 Order at 4. 275 Case No. 2021-00103, Sept. 30, 2021 Order at 26. 276 Kollen Direct Testimony at 28. 277 Kollen Direct Testimony at 29. 278

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margins would be deferred to a regulatory liability and then amortized as a reduction to the revenue requirement in a future base revenue proceeding. 279 The Joint Settlement proposed changes to the existing EM shifting it to a symmetrical earnings mechanism (SEM). As part of the Joint Settlement, the Parties 280 agreed that EKPC should collect or return any margins to its Owner-Members for contemporaneous collection or pass-through to Retail Members in the form of a bill

charge or credit in the event that EKPC's per book margins fall below a 1.40 TIER or are

in excess of a 1.60 TIER in any calendar year. Any margins to be collected or returned 281 would be allocated based upon the EKPC's determination of total revenue from its Owner- Members for the most recent calendar year in total and by applicable rate classes. The 282 SEM would remain in place until EKPC's base rates are next adjusted but may be renewed at that time. In support of the mechanism, EKPC argued that its financial 283 interests are fundamentally different from that of an investor-owned utility where

shareholder owners are rarely the same persons as the utility's customers, as there is no

fiduciary obligation to maximize profit to benefit shareholders. 284 EKPC provided the general process of operation if the Commission were to approve the SEM. First, EKPC would file a tariff for Commission review within 30 days

Kollen Direct Testimony at 28. 279 Scott Supplemental Testimony at 5. 280

281 282 283

EKPC's Post-Hearing Brief at 7. 284

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of the Commission entering a final Order approving the Stipulation. EKPC would make 285 an entry on its books to account for the difference between its unaudited per books margins and the higher or lower band of the SEM as of December 31st of each year. 286 EKPC would then file with the Commission (with a copy to Owner-Members) a statement by February 1st that sets forth the amount of the over/under collection and how the amount is broken down by customer rate class revenue by Owner-Member distribution cooperative. If the amount is $10 million or more, EKPC's filing would also include a 287 statement as to how it plans to refund/collect the amount. If the amount is less than 288 $10 million, EKPC would carry the amount forward as either a regulatory asset or regulatory liability, and it would be netted against the following year's difference. The 289 collection/refund period would be up to 12 calendar months, although EKPC would have discretion to shorten the period if it made sense to do so. At the end of the following 290 year, EKPC would repeat the process for making an entry on its books to account for the difference between its unaudited per books margins and the SEM thresholds. In 291 addition, EKPC would factor in any differences (positive or negative) between its

Scott Supplemental Testimony at 7. 285 Scott Supplemental Testimony at 7. 286 Scott Supplemental Testimony at 7. 287 Scott Supplemental Testimony at 7. 288 Scott Supplemental Testimony at 7-8. 289 Scott Supplemental Testimony at 8. 290 Scott Supplemental Testimony at 8. 291

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unaudited and audited for the prior year, any under/over collections from the current year and any other amounts necessary to true-up the annual refund/collection. 292 EKPC provided its trailing 12-month TIER which is shown in the below chart: 293

EKPC explained that a trailing 12-month TIER more accurately reflects TIER without the variation that occurs with the seasons that appear for the monthly tier. 294 EKPC explained that, while the minimum 1.1 TIER would meet RUS debt covenants, it would not provide enough annual margin and cash flow to satisfy rating agencies. Following the proposed Joint Settlement, EKPC alleged it spoke with ratings 295 agencies who indicated the bottom end of the TIER band (1.4) is as low as they would

Scott Supplemental Testimony at 8. 292 EKPC's Response to Staff's Post-Hearing Request, Item 1, Attachment. 293 EKPC's Response to Staff's Post-Hearing Request, Item 1. 294 Scott Supplemental Testimony at 8. 295

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like to see EKPC's TIER. EKPC explained that, since its last rate case, EKPC has 296 never achieved its authorized TIER. 297 EKPC explained that the SEM would allow EKPC to avoid filing pancake rate cases in the next few years as it goes through the investment cycle and brings new generation assets online and reduce volatility in future years. EKPC also explained that the SEM 298 is attractive to credit rating agencies because it helps ensure that EKPC can achieve its financial metrics and adequately service its growing debt expense. EKPC stated it 299 anticipates that the revenue certainty the SEM gives EKPC will provide the comfort needed for Fitch to eventually remove the negative outlook and likelihood of a downgrade

during EKPC's period of increased capital expenditures and EKPC's likelihood of

maintaining an A rating from S&P is also strengthened by the SEM. 300 EKPC stated: If the settlement is not accepted EKPC will likely need to file another rate case in 2026 to shore up financials in 2027. If EKPC continues to end fiscal years with TIER metrics in the 1.1 - 1.2 range, borrowing the necessary funds for the generation assets will be difficult. The expenses that are causing the SEM to be large, including RTEP and generation maintenance, would also be in the next base rate case. The next case will probably request an increase of over $100M, causing a similar increase in member costs on a monthly basis as the SEM. 301

Scott Supplemental Testimony at 5. 296 Scott Supplemental Testimony at 5. 297 Scott Supplemental Testimony at 7. 298 Scott Supplemental Testimony at 7. 299 EKPC's Response to Staff's Post-Hearing Request, Item 15. 300 Scott Supplemental Testimony at 9. 301

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EKPC estimated that the monthly bill impact to residential members would be $5.39. 302 EKPC also provided an example calculation of the SEM impact using the calendar year

1. The calculation showed a TIER of 1.18 in 2023, which resulted in a revenue deficiency of $23.517 million, which would have been collected from customers had the SEM been in place at that time. 303

Commission finds that the proposed SEM should be denied for the reasons discussed below. At the hearing, EKPC was unsure of whether some of the difficulties with the software experienced with the EM would also be an issue with the SEM. EKPC stated 304 that there were concerns regarding the unknown in relation to the SEM, and that the Joint Settlement was specifically vague with relationship to the Owner-Members on the distribution side because EKPC did not have time to work through all of those concerns. 305 The Commission is concerned about the lack of evidence and planning regarding implementation and process of the SEM with member cooperatives. There is not sufficient information for a known and reasonable amount of revenue likely to be returned to or recovered from customers during the sharing mechanism period. Based on the evidence provided by EKPC, customers would have the potential for large bill increases during this period, comparable to increases seen in a general rate case. This Commission

EKPC's Response to Staff's Post-Hearing Request, Item 7. The bill impact is estimated by 302dividing the amount of under-recovery by the average customer count, and then dividing by the number of

months the recovery is amortized over.   󰇛 󰇜  . 

EKPC's Response to Staff's Post-Hearing Request, Item 4. 303 HVT of Dec. 8, 2025 Hearing, Hearing Testimony of Jacob Watson at 02:26:17-02:26:58. 304 HVT of Dec. 8, 2025 Hearing, Hearing Testimony of Jacob Watson at 02:27:11-02:27:44. 305

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is especially concerned given that large bill increases may occur without customer notice. The Commission is further concerned that the proposed SEM would be in effect during a period in which EKPC is undertaking a significant build-out of new generation resources, including the construction of the Liberty RICE facility in Casey County consisting of 306 twelve reciprocating internal combustion engines capable of producing approximately 214 MW of capacity, as well as additional natural gas-fired generation resources approved in a related proceeding to support reliability and projected load growth. 307 During this build-out phase, EKPC will incur substantial capital and operational costs associated with placing new generation into service, increasing the likelihood that customers could be subject to upward adjustments under the SEM. Furthermore, the last time that EKPC achieved a TIER of at least 1.4 was at the end of 2022 which provides evidence that EKPC is more likely to collect from its customers than issue a refund. Also, the Commission does not see the value in authorizing the SEM as opposed to a full rate case, where the Commission would be able to more thoroughly review

EKPC's revenues and expenses. While the Commission acknowledges that the SEM would have the potential to benefit EKPC's credit ratings, filing more frequent rate cases

has similar potential. Furthermore, a full rate case allows for customers to receive notice on the proposed increases, interested parties to intervene, and, at a minimum, customers to provide public comment. During such a critical phase of build-out that is going on

Case No. 2024-00310, Electronic Application of East Kentucky Power Cooperative, Inc. For 1) 306 A Certificate of Public Convenience and Necessity to Construct a New Generation Resource; 2) A Site Compatibility Certificate; And 3) Other General Relief (Ky. PSC May 20, 2025), Order. Case No. 2024-00370, Electronic Application of East Kentucky Power Cooperative, Inc. For 1) 307 Certificates of Public Convenience and Necessity to Construct a New Generation Resources; 2) For A Site Compatibility Certificate Relating to The Same; 3) Approval of Demand Side Management Tariffs; And 4) Other General Relief (Ky. PSC July 3, 2025), Order.

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throughout the energy sector including EKPC, by authorizing the SEM the Commission would be abdicating its statutory authority for a determination of fair, just and reasonable rates at the exact time of significant rate change. While the Commission respects the efforts of the parties in developing the SEM to address concerns with frequent rate cases, this mechanism as proposed is not the answer. The Commission is also concerned that some of the practical aspects of the SEM, such as how each Owner-Member would implement the SEM, have not been thought out. As noted above, originally EKPC requested to end the EM citing difficulties implementing the program. While EKPC worked to address some of these concerns by creating the $10 million threshold and allowing flexibility to Owner-Members, EKPC did not provide sufficient evidence that their solutions would fix the original issues EKPC had with the EM, which was also only proposed within the context of a Joint Settlement. Therefore, the Commission finds that the Joint Settlement provision related to the

SEM should be denied. Due to EKPC's stated reasons involving difficulties and inefficiencies regarding the implementation of the EM, the Commission finds that EKPC's

request to terminate the EM is reasonable and should be granted. The Commission encourages EKPC to consult further with the member cooperatives to address concerns regarding affordability, credit ratings as well as the practical implications related to meeting TIER and the impact to the member cooperatives' ratepayers. RTEP TRACKER In its application, EKPC requested an RTEP tracking mechanism to help protect its financials from future swings in RTEP expenses (RTEP Tracker). 308

Watson Direct Testimony at 31. 308

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since joining PJM in 2013, EKPC's RTEP expenses have remained relatively stable, not exceeding $14.2 million annually, but a dramatic shift occurred in 2025 when EKPC's RTEP increased to approximately $29.5 million. EKPC explained that while it is 309 unknown what future RTEP expenses will be, EKPC is anticipating additional significant increases due to anticipated large load growth and deactivation trends across the entirety of the PJM region. 310 With the proposed tracker, EKPC would record a debit or credit to the regulatory asset for RTEP expenses depending on whether the RTEP expenses are greater than or less than the amount of RTEP expenses included in base rates. EKPC would seek 311 amortization and recovery of those expenses in future rate cases over a reasonable time period. 312 The Attorney General/Nucor originally argued that EKPC's request to defer increases in a single expense is selective and inequitable. 313 pointed out that the RTEP tracker does not address increases in revenues compared to the amounts included in the base revenue requirement in this proceeding that would offset the increases in the RTEP expenses and increase EKPC's margins and earned TIER, all else equal. The Attorney General/Nucor recommended the Commission deny EKPC's 314 request for an RTEP Tracker, but in the alternative recommended the Commission allow

Watson Direct Testimony at 31. 309 Watson Direct Testimony at 31. 310 Watson Direct Testimony at 31. 311 Watson Direct Testimony at 31. 312 Kollen Direct Testimony at 30. 313 Kollen Direct Testimony at 29-30. 314

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EKPC to defer increases in RTEP expenses and direct EKPC to defer increases in non- member energy and capacity revenues, including interruptible capacity revenues for refund in future base revenue proceedings. However, in response to discovery, the 315 Attorney General/Nucor stated that, if EKPC's request to defer increases in RTEP was

approved, then future increases in RTEP expenses would not affect EKPC's margins

regardless of whether the EM was terminated or maintained. 316 General/Nucor explained that the deferral of the increases in RTEP expense would hold the expense recorded for accounting and ratemaking purposes to the test year level until the effective date of new base rates. 317 The Joint Settlement provided that the SEM eliminates the need for the RTEP Tracker and withdraws EKPC's requests for it. 318

Commission finds that EKPC's original application request for the RTEP tracker that

would record a debit or credit to the regulatory asset for RTEP expenses should be approved because of the predicted volatility associated with future RTEP expense. As the Commission denied the SEM above, the Commission finds that EKPC's original reasoning for the necessity of the RTEP tracker to be reasonable. Tracking EKPC's RTEP expenses and recording a debit or credit to a regulatory asset is a reasonable approach, as opposed to the Commission approximating an amount to be included in

Kollen Direct Testimony at 30. 315 Attorney General/Nucor's response to Staff's First Request, Item 13. 316 Attorney General/Nucor's response to Staff's First Request, Item 13. 317

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base rates based on extremely volatile historical data that would surely result in significant under or over recovery of such expenses. Additionally, as the Commission approved

EKPC's request to terminate the EM above, the Commission finds that the Attorney General/Nucor's recommendation to also direct EKPC to defer increases in non-member

energy and capacity revenues, including interruptible capacity revenues for refund in future base revenue proceedings should be denied. As the amounts of RTEP expenses have been increasing and recently unpredictable, there is potential for huge increases that are not yet known, the Commission finds that EKPC has presented sufficient evidence that these expenses are extraordinary, nonrecurring expenses which cannot reasonably be anticipated or included

in the utility's planning due to the recent fluctuations in RTEP expenses and the potential

for future unknown increases in this expense. GENERATION MAINTENANCE TRACKER As part of the Stipulation and Settlement Agreement in Case No. 2021-00103, the parties agreed to normalize generation maintenance expense based upon a historic five- year average and created a Generation Maintenance Tracker, effective for the year ending December 31, 2022, and thereafter. In the Generation Maintenance Tracker, 319 EKPC would record a regulatory asset or regulatory liability for 75 percent of all actual generation and maintenance expenses over or under the established historical five-year average with the recovery of the regulatory asset or refund of the regulatory liability to be

Case No. 2021-00103, Sept. 30, 2021 Order at 24-25, and Application, Exhibit 15, Direct 319Testimony of Michelle K. Carpenter (Carpenter Direct Testimony) (filed Aug. 1, 2025) at 7.

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addressed in the next base rate case. The remaining 25 percent would be excluded 320 from recovery in base rates. In Case No. 2022-00430, the Commission clarified that 321 the historic five-year average of generation maintenance expenses and amounts contemplated in the tracker should exclude generation maintenance expenses recovered through the Environmental Surcharge. In the application, EKPC proposed to continue 322 the Generation Maintenance Tracker and allow EKPC to recover 75 percent of generation maintenance expense above the threshold amount. 323 As part of the Joint Settlement, EKPC requested, and the parties agreed to terminate the Generation Maintenance Tracker. EKPC explained that the SEM would 324 eliminate the need for EKPC to track and record generation maintenance expenses as regulatory assets in excess of what is currently allowed in base rates. EKPC argued 325 the SEM would grant EKPC the ability to book the excess costs against its margin and recover those costs, if EKPC's TIER went below 1.40, through the SEM in the following year. 326

Commission finds that EKPC's original request to continue the Generation Maintenance

Carpenter Direct Testimony at 7. Case No. 2021-00103, Sept. 30, 2021 Order, Appendix A at 320Article 5.

Case No. 2022-00430, Electronic Application of East Kentucky Power Cooperative, Inc. to 322Amend the Joint Stipulation and Settlement Agreement and the Commission's Final Order in Case No. 2021-00103 (Ky. PSC Jan. 27, 2023), Order at 3. Application, Exhibit 16, Attachment JRW-1, Schedule 1.25, 1.26, and 1.27. 323 Joint Settlement at 3 and Scott Supplemental Testimony at 14. 324 Watson Supplemental Testimony at 11. 325 Watson Supplemental Testimony at 11. 326

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Tracker and allow EKPC to recover 75 percent of generation maintenance expense above the threshold amount, or refund 75 percent of generation maintenance expense below the threshold amount, should be approved. It is the Commission's understanding that the proposed termination of the Generation Maintenance Tracker is directly related to the

Parties' petition for approval of the SEM. Although the Commission approved an

increased threshold amount based on a recent five-year average to be included in base rates above, the Commission denied the SEM above and therefore finds that it is reasonable to allow EKPC to continue to track and record generation maintenance expenses as regulatory assets in excess of what is currently allowed in base rates through the Generation Maintenance Tracker. REVENUE ALLOCATION AND RATE DESIGN COST-OF-SERVICE STUDY (COSS) In its application, EKPC performed a COSS based on operation costs for the test period. EKPC allocated production fixed costs utilizing the Average and Excess (A&E) 327 method, which EKPC stated was approved in EKPC's prior general rate case. EKPC 328 used the 12 Coincident Peak (12 CP) methodology to allocated transmission demand costs. EKPC stated that the interruptible service rider was addressed in the COSS by 329 assigning a demand cost credit per kW based on levelized carrying costs of a combustion

Application, Exhibit 17, Direct Testimony of Jeffrey W. Wernert, Jr. (Wernert Direct Testimony) 327(filed Aug. 1, 2025) at 2. Wernert Direct Testimony at 7. 328 Wernert Direct Testimony at 10. 329

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turbine generating unit. The table below illustrates the present and the application's 330 proposed class rates of return on rate base: 331

Prior to the Joint Settlement, the Attorney General/Nucor stated that EKPC's proposed COSS contained six errors that require corrections. The errors included the 332 following: an incorrect calculation of interruptible revenue for the Large Special Contract class; no adjustment for the Economic Development Rate (EDR) credits; no adjustment for fuel and purchased energy imbalance; incorrect calculation of Rate G's non-coincident peak demand; incorrect calculation of the 12 CP allocation; and a failure to normalize weather in the A&E allocation and test year revenue. The correction of these errors 333 resulted in a total revenue requirement increase target of $45,410,526, or 4.13 percent. 334

Wernert Direct Testimony at 13. 330 Wernert Direct Testimony, Table 2 at 17. 331 Baron Direct Testimony at 6-7. 332 Baron Direct Testimony at 6-7. 333 Baron Direct Testimony, Table 10 at 28. 334

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Special Contract - (2.47%) (2.47%) Rate C 29.50% 31.60% 0.02% 4.94% Rate E Rate B Rate G Pumping Station (0.25%) (2.92%) (3.76%) (0.01%) 2.25% 5.10% 4.49% 2.97% Total System Proposed Rate of Return Current Rate of Return 1.45% 4.64%

In rebuttal testimony, EKPC addressed four out of the six errors. Out of the four 335 EKPC addressed, two of the errors were agreed upon by EKPC. EKPC agreed and 336 corrected the calculation of Rate G's non-coincident peak demand allocation and the calculation of the 12 CP allocator. EKPC disagreed with the basis behind the 337 calculation of the interruptible revenue for the Large Special Contract class. EKPC 338 stated that the current interruptible credits were settled rates where a 12 percent reserve margin was utilized in the calculation. If EKPC were to apply the interruptible avoided 339 costs on an equal basis as the current credit of $6.22/kW-month, then the avoided costs would be overstated in the COSS as the reserve margin is now only 7 percent. EKPC 340 also disagreed with the Attorney General/Nucor's adjustment to the EDR credits in the COSS, stating that treating the EDR credits similarly to the interruptible credits would negatively impact other rate classes by supporting a higher base rate increase to cover additional deficiencies shown in the COSS. Additionally, EKPC cited to the 341

Commission's Administrative Order No. 327 which states that EDR credits should not

adversely affect nonparticipating ratepayers. 342

Wernert Rebuttal Testimony at 2. 335 Wernert Rebuttal Testimony at 7-8. 336 Wernert Rebuttal Testimony at 7-8. 337 Wernert Rebuttal Testimony at 3. 338 Wernert Rebuttal Testimony at 3. 339 Wernert Rebuttal Testimony at 4. 340 Wernert Rebuttal Testimony at 5-6. 341 Wernert Rebuttal Testimony at 6, citing Kentucky Public Service Commission Administrative 342Order 327(Ky. PSC Sept. 24, 1990) at 17.

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The proposed Joint Settlement did not specifically acknowledge the application's proposed COSS and the issues raised throughout the pendency of the case; however, its approval falls under the catch-all provision, paragraph 7. 343 Having considered the record and otherwise being sufficiently advised, the

Commission finds EKPC's proposed COSS, with the agreed upon modifications, to be

reasonable. REVENUE ALLOCATION In its application, EKPC explained that the results of the COSS were relied on to develop its proposed revenue requirement increase allocation. In addition, EKPC 344 stated it relied upon the principle of gradualism to inform its allocation. EKPC proposed 345 to allocate revenue in a uniform fashion, based on class rates of return. For example, 346 Rate B and Rate C, which had rates of return slightly below the overall system rate of return, were proposed to have that same revenue increase of 9 percent. The proposed 347 class revenue increases are as follows: 348

Wernert Direct Testimony at 16. 344 Wernert Direct Testimony at 16. 345 Wernert Direct Testimony at 16. 346 Wernert Direct Testimony at 16-17. 347 Application, Exhibit 17, Attachment JWW-4 at 1. 348

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Special Contract - Pumping 0.00% $0 11.00% Proposed Increase (%) Proposed Increase ($) Rate E Rate B Rate C Rate G Stations $55,671,585 11.00% $6,898,140 $2,723,402 $5,027,007 6.94% 9.00% 9.00%

Prior to the Joint Settlement, the Attorney General/NUCOR did not recommend

any revisions to EKPC's proposed revenue requirement increase allocation.

In the proposed Joint Settlement, the Parties agreed to allocate the revenue increase in the following manner, 4.95 percent to Rate E and 9.64 percent to the remaining rate classes, excluding pumping stations. Additionally, the Parties agreed 349 to increase the Interruptible Credits outlined in Rate D by $2.00/kW, which results in a $8,093,981 credit to the revenue increase. The addition of the increased Interruptible 350 Credits results in a new revenue allocation, as illustrated below: 351

The Commission acknowledges the impact that increased Interruptible Credits have on EKPC and its Owner-Members' customers. However, the Joint Settlement's revenue allocation, including the increased Interruptible Credits, as it stands, undervalues

Joint Settlement at 2-3. 349 Watson Supplemental Testimony at 10. 350 Joint Settlement, Exhibit C, "EKPC Summary" Tab, columns D and I. 351

-72- Case No. 2025-00208 Stipulated Revenue Stipulated Revenue Allocation before Allocation after Special Contract Pumping 0.00% 0.00% 9.64% 2.25% Total System Rate B Interruptible Credit Interruptible Credit $79,731,915 9.64% 7.49% 8.72% Rate E Rate C Rate G Stations 4.95% 9.64% 9.64% 9.64% 2.50% $348,497 4.95% 7.94% 7.96% 9.64% Proposed Increase (%) Total System Proposed Increase ($) 5.99% 5.23%

the findings in EKPC's filed COSS. A 2.25 percent revenue increase to the Large Special

Contract class would continue to allow for other rate classes, specifically Rate E, to subsidize its cost to serve. The Commission notes that Rate E primarily serves residential customers and is already allocated the majority of the revenue increase. The

Commission has an obligation to strike a balance between all customers' financial interests and the utility's ability to provide adequate, reliable service. The Commission finds that the Stipulation's revenue allocation does not provide the most fair, just, nor reasonable solution for all of EKPC's ratepayers, and therefore finds it necessary to

modify the revenue allocation. Based upon the results of the EKPC's COSS, the Commission finds that proposed revenue requirement increase allocation found in the application better reflects the results of the COSS. Due to the Commission's further adjustments to the approved revenue requirement increase, the Commission has determined the following class revenue increases to be reasonable:

RATE DESIGN In its application, EKPC proposed a rate design that was guided by the following ratemaking principles: rates should recover the cost-of-service, rates should be equitable by minimizing subsidization, and rates should consider the overall bill impacts to each

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Special Contract - Pumping 0.00% $0 Approved Revenue Approved Revenue

Rate E $34,989,502 4.36% Rate B Rate C Rate G Station $15,314,761 $5,673,790 $2,243,948 $5,114,290 $348,497 18.59% 11.19% 7.40% 7.42% 2.50% Increase (%) Increase ($)

customer class. EKPC stated that a 50-50 split between increasing the energy and 352 demand charges was utilized in order to strike a balance between moving rates towards the cost-of-service, while also minimizing rate shock. None of the intervenors took 353

issue with EKPC's rate design methodology.

The Joint Settlement revised the rates to meet the appropriate revenue requirement increase allocations for each class. 354 The Commission finds the method in which EKPC disbursed the allotted revenue requirement increases to the demand and energy charges to be reasonable. Because the Commission made further adjustments to the approved revenue requirement increase and the allocation of such revenue, the Commission modified the rates in the same

manner as proposed in EKPC's application. The Commission finds the revised rates to

be reasonable, as reflected in Appendix C to this Order, and should be approved. INTERRUPTIBLE CREDITS EKPC's application did not seek to revise the interruptible credits. However, 355 the Attorney General/Nucor originally stated that because EKPC utilized the installed cost of a combustion turbine and not the cost contained in its recently approved CPCN, the 356 value of the credits may be understated. The Attorney General/Nucor recalculated the 357

Wernert Direct Testimony at 18. 352 Wernert Direct Testimony at 19. 353 Joint Settlement, Exhibit C. 354 Wernert Direct Testimony at 13. 355 Case No. 2024-00310, Electronic Application of East Kentucky Power Cooperative, Inc. for 1) 356 A Certificate of Public Convenience and Necessity to Construct a New Generation Resource; 2) A Site Compatibility Certificate; and 3) Other General Relief, (filed Sep. 20, 2024), Direct Testimony of Julia J. Tucker at 23. Baron Direct Testimony at 36. 357

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interruptible credits based on the cost of $1,329 per kW, instead of the $836 per kW used

in EKPC's application, and determined that the interruptible credit should be ($11.54) per

kW-month. However, in the interest of the principle of gradualism, the Attorney 358 General/Nucor recommended increasing the interruptible credits by only ($2.00) per kW- month. EKPC did not file rebuttal testimony in regard to this recommendation. 359 In the Joint Settlement, the Parties agreed to the ($2.00) per kW-month increase recommended by witness Baron. 360 EKPC has two recently approved CPCNs, one for a Combined Cycle Gas Turbine and another for a Reciprocal Internal Combustion Engine. 361 362 General/Nucor recommendation did not use either of the approved units as a proxy when calculating the updated interruptible credits. EKPC also did not use the costs 363 associated with either of the approved CPCNs in its calculation. The Commission 364 inserted the values for both units in exhibit JRW-3 and determined that the interruptible 365 credits would still need a significant increase, resulting in an initial credit value of

Baron Direct Testimony at 39-40. 358 Baron Direct Testimony at 40. 359 Joint Settlement at 5-6. 360 Case No. 2025-00370, Electronic Application of East Kentucky Power Cooperative, Inc. For 1) 361 Certificates of Public Convenience and Necessity to Construct a New Generation Resources; 2) For a Site Compatibility Certificate Relating to the Same; 3) Approval of Demand Side Management Tariffs; And 4) Other General Relief, (Ky. PSC July 30, 2025) Order at 46. Case No. 2024-00310, May 20, 2025 Order at 28. 362 Baron Direct Testimony at 36. 363 Watson Direct Testimony at 28. 364 The values for the Combined Cycle Gas Turbine were found in Case No. 2024-00370, Direct 365Testimony of Brad Young, Attachment BY-1. The values for the Reciprocal Internal Combustion Engine were found in Case No. 2024-00310, Direct Testimony of Brad Young, Attachment BY-1.

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approximately ($9-$12) per kW-month. Nonetheless, the Commission favors the principle of gradualism when determining fair, just and reasonable rates, and maintained this ideology when determining the reasonableness of the increased interruptible credits. Based upon the record and being otherwise sufficiently advised, the Commission finds the gradual ($2.00) per kW-month increase to the interruptible credits reasonable, as reflected in Appendix C to this Order, and should be approved. The following table summarizes the Commission-approved revenue allocation including the interruptible credits:

Appendix D to this Order details the allocation of revenue, inclusive of the interruptible credit, to the 16 Owner-Members.

The Commission also finds that in EKPC's next general base rate case, EKPC

should provide updated interruptible credit calculations using its most recently approved generation unit as a proxy.

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Large Special 11.20% Including Interruptible Credit Special Contract - Including Interruptible Credit 0.00% $0

Rate E Rate B Rate C Rate G Contract Pumping Stations $34,972,154 $4,965,286 $1,730,157 $4,346,698 $348,497 4.36% 6.48% 5.72% 9.51% 2.50% ($) (%)

TARIFF CHANGES RATE B In its application, EKPC proposed to revise language to allow Owner-Members taking service under Rate B to limit the number of contract demands to two updates per year. The current tariff does not limit the number of instances an Owner-Member can 366 update its contract demands. EKPC stated that including the language would improve 367

EKPC's ability to recover capacity costs. EKPC explained that allowing Owner- 368 Members to change the contract demand on a monthly basis has led to instances of contract demands being reset in eleven of twelve months, which has the effect of avoiding the excess demand charge by increasing contract demand in months demand is assumed to be higher, and decreasing contract demand in months demand is assumed to be lower. 369 EKPC also noted administrative burden as a factor in its decision to implement a limit of two updates per year. EKPC explained that each change takes roughly 30 370 minutes for an employee to process not including time spent by supervisors for review and approval. EKPC stated that in 2024, EKPC processed 180 contract demand 371 changes for Rate B. 372

Watson Direct Testimony at 28. 366 EKPC's Response to Staff's Second Request, Item 18. 367 Watson Direct Testimony at 28. 368 EKPC's Response to Staff's Second Request, Item 18. 369 EKPC's Response to Staff's Second Request, Item 18. 370 EKPC's Response to Staff's Second Request, Item 18. 371 EKPC's Response to Staff's Second Request, Item 18. 372

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Revisions to Rate B also included a minor contextual change. 373

374 The Commission acknowledges the administrative burden that the current tariff may create by not establishing a limit to contract demand updates. The Commission also notes that due to Owner-Members having the ability to update contract demands on an unlimited basis, EKPC is missing out on revenue associated with Rate B's excess demand charge. Having considered the record and otherwise being sufficiently advised, the Commission finds the proposed language revisions to the Rate B tariff reasonable and should be accepted. RATE D In its application, EKPC proposed two language revisions to the Rate D tariff. EKPC proposed to remove the interruptible contract demand cap of up to 20,000 kW. 375 EKPC explained that removing the cap of 20,000 kW would alleviate the pressures of capacity planning as well as aiding in economic development for EKPC and its Owner-

Member's service territories. EKPC also proposed to remove the specified timeframe 376 in which interruptions may occur. EKPC stated that since interruptions in PJM's 377 Locational Marginal Pricing (LMP) could warrant economic interruptions at any time,

Application, Exhibit 7 at 3. 373

Watson Direct Testimony at 29. 375 Watson Direct Testimony at 29. 376 Watson Direct Testimony at 29. 377

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removing the specified timing restrictions from the tariff would allow EKPC to interrupt when warranted by the LMP levels. 378

379 The Commission acknowledges that removing the 20,000 kW contract demand cap would allow EKPC to offer the interruptible program to larger load customers than currently served under Rate D. Additionally, removing the specified timing restrictions 380 from the Rate D tariff would allow EKPC the ability to interrupt when called upon by PJM. Having considered the record and otherwise being sufficiently advised, the Commission finds the proposed language revision to the Rate D tariff reasonable and should be accepted. RATE H In its application, EKPC proposed to remove Rate H Option B's pilot status. 381 EKPC stated that the pilot program expired in March 2025. EKPC stated that Option 382 B should become permanent and that the option allows renewable energy to offset a portion of energy consumed by end-use customers. From September 2024 to August 383 2025, Option B offset approximately 863 MWh of energy consumed. 384

EKPC's Response to Staff's Second Request, Item 20. 378

EKPC's Response to Staff's Post-Hearing Request, Item 17. 380 Watson Direct Testimony at 29. 381 Watson Direct Testimony at 29. 382 Watson Direct Testimony at 29. 383 EKPC's Response to Staff's Second Request, Item 21, Attachment, "CF" tab. 384

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Revisions to the Rate H tariff also included minor contextual changes. 385

386 The Commission notes the importance of offsetting generation through renewable resources for capacity planning purposes. Having considered the record and otherwise being sufficiently advised, the Commission finds the permanent implementation of Rate H Option B reasonable and should be accepted. The Commission also finds the minor contextual changes proposed by EKPC in the Rate H tariff to be reasonable. OTHER ISSUES Smart Grid Investments

Pursuant to the Commission's Order in Case No. 2012-00428 , which directed 387 all jurisdiction utilities to identify Smart Grid investments in each rate case, EKPC included a discussion of smart grid investments. EKPC stated that since its last rate case, EKPC 388 has installed devices at multiple sites, such as electronic, microprocessor-based relays and meters that capture Power Quality (PQ) data, across its electric power system that could be considered smart grid technology and these devices provide digital information and control technology that improves reliability, security, and efficiency of the electric grid. EKPC stated that the smart grid investments provide greater visibility and control 389

Application, Exhibit 7 at 12. 385

Case No. 2012-00428, the Consideration of the Implementation of Smart Grid and Smart Meter 387Technologies (Ky. PSC. Apr. 13, 2016), Order at 33. Application at 9. 388 Direct Testimony of Denver York (York Direct Testimony) at 4. 389

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for the system operators to more readily locate faults and restore service. The 390 Commission finds that EKPC has complied with the directive of No. 2012-00428. RTO Reporting Requirement In its application, EKPC requested relief from filing an annual comprehensive report identifying benefits and costs that accrue from its PJM Interconnection, LLC (PJM) membership and comparing these to benefits and costs if EKPC left PJM as originally required in Case No. 2012-00169 and as modified in Case No. 2021-. EKPC stated 391 that it believes it should be relieved from continuing to provide a speculative and

overburdensome "what-if" analysis. EKPC stated that it has repeatedly demonstrated 392 that the decision to integrate with PJM was advantageous to its Owner-Members and the Owner-Members' retail-members. EKPC stated that regardless of the annual report, it 393 would continue to examine the benefits of its membership with PJM. 394 In Case 2012-00169, the Commission required EKPC to file by May 31 of each year a comprehensive report setting forth in detail the amount of transmission rights awarded and purchased; a description of hedging plans and strategies to address transmission congestion and market prices for capacity and energy; a breakdown by

category of the prior years' benefits and costs of PJM membership; and a projection of

York Direct Testimony at 5. 390 Application at 11-12. 391 Application, Exhibit 14, Direct Testimony of Gregory H. Cecil (Cecil Direct Testimony) (filed Aug. 3921, 2025) at 8. Cecil Direct Testimony at 8. 393 HVT of Dec. 8, 2025 Hearing, Hearing Testimony of Gregory H. Cecil at 01:47-58-01:48:29. 394

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future benefits and costs reflecting the most recent PJM capacity auction results. In 395 Case No. 2021-00103, the Commission revised this and found that the reporting requirement EKPC should file an annual report identifying benefits and costs that accrue from its PJM membership and comparing these to benefits and costs if EKPC left PJM. 396 The Joint Settlement recommended approving this request.

Commission finds that this Joint Settlement provision should be approved with modifications. The Commission finds that EKPC should be relieved of its annual filing requirements, but that it should continue to file a report with the same information as required by Case No. 2021-00103 within the context of its next integrated resource plan (IRP) filing. EKPC acknowledged that the benefits of remaining in PJM is something 397 that could be looked at in the context of an IRP. While the Commission acknowledges 398

the benefits of EKPC's membership in PJM, examination of these benefits should

continue to be explored as part of its integrated resource planning process.

Case No. 2012-00168, Application of East Kentucky Power Cooperative, Inc. to Transfer 395Functional Control of Certain Transmission Facilities to PJM Interconnection, LLC (Ky. PSC Dec. 21, 2012), Order at 19-20. Case No. 2021-000103, Sep. 30, 2021 Order at 31. 396 HVT of Dec. 8, 2025 Hearing, Hearing Testimony of Gregory H. Cecil at 1:48:38-1:48:48. 397 HVT of Dec. 8, 2025 Hearing, Hearing Testimony of Gregory H. Cecil at 1:48:18-1:48:48. 398

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Bluegrass Station Reporting Requirements In its application, EKPC requested relief from annual operating reports setting forth details of the performance of the Bluegrass Station from Case No. 2015-00267. The 399 Commission required EKPC to file annual operating reports providing the Commission with detailed updates on the performance of the Bluegrass Station units and EKPC's assessment of any potential changes in existing or potential environmental regulations that would impact the Bluegrass Station. The Commission also directed EKPC to 400 include in its annual reports its evaluation of how the Bluegrass Station units would qualify as a Coincident Peak (CP) product and how EKPC will address the related risk exposure. 401 EKPC stated that the starting reliability for the units has remained at approximately 99.2 percent since 2021, while the equivalent forced outage rate has remained below 2.5 percent for the past four years. EKPC stated that it recently made substantial 402 investments in the units by making them dual-fuel capable, performed a hot gas path inspection on each, upgraded the distributed control system, and completed several other

smaller projects to ensure the units' reliability for years to come. EKPC stated that from 403 an environmental perspective, Bluegrass Station is, and has been, complying with the

Application at 12; Case No. 2015-00267, Application of East Kentucky Power Cooperative, Inc. 399 for Approval of the Acquisition of Existing Combustion Turbine Facilities from Bluegrass Generation Company, LLC at the Bluegrass Generating Station in LaGrange, Oldham County, Kentucky and for Approval of the Assumption of Certain Evidences of Indebtedness, (Ky. PSC Dec. 1, 2015), Order at 29-

Case No. 2015-00267, Dec. 1, 2015 Order at 28. 400 Case No. 2015-00267, Dec. 1, 2015 Order at 29. 401 Cecil Direct Testimony at 9. 402 Cecil Direct Testimony at 9. 403

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Clean Air Act, Clean Water Act, and Spill Prevention, Control and Countermeasure

(SPCC) since EKPC's ownership began. EKPC stated that should EPA regulations 404 change, EKPC will work with state and federal regulators to maintain compliance. 405 EKPC stated that regarding the Commission's initial concern about the Bluegrass Station units qualifying as a CP product in PJM and how EKPC addresses any related risk exposure, EKPC points out that all three Bluegrass units received payments from the PJM Reliability Pricing Model auctions as CP units since becoming part of EKPC's generation fleet, and to address risk exposure, EKPC added dual-fuel capability to the plant to ensure its availability during CP events. EKPC stated that while EKPC is always willing to 406

provide information responsive to the Commission's needs, the value of these particular

reports appears to be minimal. 407 The Joint Settlement recommended approving EKPC's request for relief from the annual reporting requirements associated with the Bluegrass Station. 408

Commission finds that EKPC requested for relief from annual operating reports related to Bluegrass Station is granted consistent with the Joint Settlement. EKPC has filed these reports every year since 2015, and the Commission agrees that the value of further reports would be minimal.

Cecil Direct Testimony at 9. 404 Cecil Direct Testimony at 9. 405 Cecil Direct Testimony at 9-10. 406 Cecil Direct Testimony at 10. 407

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Timing of Filing of Small Power Production and Cogeneration Rates EPKC requested to realign the filing of EKPC's small power production and cogeneration rates to a biennial basis in accordance with 807 KAR 5:054. 807 KAR 409 5:054 Section 5(1)(a) states that all electric utilities with annual retail sales greater than 500 million kilowatt hours shall provide data to the commission from which avoided costs may be derived not later than June 30, 1982, and not less often than every two (2) years thereafter unless otherwise determined by the commission. The Parties also agreed with this request in the Joint Settlement. In Case No. 2008- 410 00128, the Commission ordered EKPC and its distribution cooperatives to file annual updates to its avoided cost rates to be due by March 31 of each year. In Case No. 411 2024-00101, the Commission approved EKPC's avoided costs components. EKPC 412 stated that the stay-out period would not impact EKPC's statutory requirement of filing the power production and co-generation tariff every two years. Having considered the 413

record, and being otherwise sufficiently advised, the Commission finds that EKPC's

request to realign the filing of EKPC's small power production and cogeneration rates to a biennial basis is granted as this is more consistent with 807 KAR 5:054.

Application at 12. 409

Case No. 2008-00128, The Revision of the Cogeneration and Small Power Purchase Rates of 411East Kentucky Power Cooperative, Inc., (Ky. PSC Aug.20, 2008), Order at 4. Case No. 2024-00101, Electronic Tariff Filing of East Kentucky Power Cooperative, Inc., and its 412 Member Distribution Cooperatives for Approval of Proposed Changes to their Qualified Cogeneration and Small Power Production Facilities Tariffs (Ky. PSC Jan. 17, 2025), Order. EKPC's Response to Staff's Post-Hearing Request, Item 19. 413

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Pumping Station Special Contract Prior to the Joint Settlement, the Attorney General/Nucor argued that the Pumping Station rate fails to reasonably reflect the current EKPC Network Integrated Transmission Service 13 (NITS) transmission rate. The Attorney General/Nucor further argued that 414

the Pumping Station rate failed to recover any of EKPC's PJM Location Reliability

Charges (LRC) that are associated with serving the Pumping Station load. The 415 Attorney General/Nucor stated that the estimated costs of these Pumping Station rate

subsidies are being borne by all of EKPC's other customers and are estimated to be $3.97

million in the 12 month rate year beginning with the effective date of new rates in the case. The Attorney General/Nucor recommended that either the Pumping Station rate should be adjusted to properly reflect market rates, or the Pumping Station rate class should be included in the EKPC class cost of service study in a manner consistent with the treatment of all other EKPC rate classes. 416 In the Joint Settlement, the Parties agree that EKPC shall amend the 25-year-old Pumping Station Special Contract to eliminate the existing subsidy by either: 1) updating transmission costs from the 2000 level and including PJM generation capacity cost in a market-based contract; or 2) place the 31.9 MW gas utility on a standard cost-of-service rate. Increased revenue from subsidy elimination will benefit EKPC and ratepayers. 417 EKPC explained that the Pumping Station Special Contract customer was not a party to

Baron Direct Testimony at 5. 414 Baron Direct Testimony at 5. 415 Baron Direct Testimony at 5. 416

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the Stipulation because they did not request to intervene in this proceeding in accordance with 807 KAR 5:001. EKPC stated it would work with the affected Owner-Members to 418 renegotiate the Pumping Station contracts. 419

Commission finds that EKPC should work with the special contract customer and affected Owner-Members to renegotiate the contract pursuant to the terms of the Joint Settlement. The Commission acknowledges that as the special contract customer is not a party to this case, that it was not a party to the Joint Settlement. The Commission finds that any changes made to the special contract should be filed into the Commission's electronic tariff filing system. DSM Cost Recovery EKPC explained that it recovers its DSM costs through its base rates like any other expense incurred for the provision of electric service to the Owner-Members. EKPC 420 explained that it developed its DSM programs, both costs and benefits, by looking at EKPC as a whole rather than developing 16 separate DSM programs customized for each Owner-Member and that given this approach to DSM program development, EKPC believes it is reasonable to recover its DSM costs through its base rates. In Case No. 421 2021-00103, the Commission directed EKPC "to continue evaluating appropriate DSM programs that will minimize the need for more expensive supply-side resources and to

EKPC's Response to Staff's Post-Hearing Request, Item 14. 418 EKPC's Response to Staff's Post-Hearing Request, Item 14. 419 Watson Direct Testimony at 32. 420 Watson Direct Testimony at 32. 421

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continue monitoring the DSM costs between the Owner-Members so that any

subsidization continues to be minimal." EKPC stated that it continues to believe 422 recovery of DSM costs through base rates is still an appropriate, fair and reasonable approach. EKPC acknowledges that there is likely some minor degree of subsidization between the Owner-Members under this approach; however, it does not believe the subsidization is extensive or unreasonable. EKPC stated that the suggested rider specific to each Owner-Member with an annual true-up could be complex, time-consuming and expensive relative to any marginal reallocation of revenues. 423 No intervenors addressed this issue and it was not explicitly addressed in the Joint

Based upon a review of the case record, the Commission finds that recovering DSM costs in base rates is reasonable given the increased costs and limited benefits associated with changing the process of DSM cost recovery. IT IS THEREFORE ORDERED that:

1. The rates and charges proposed by EKPC in its application are denied
   unless otherwise discussed below.

2. The Joint Settlement, attached to this Order as Appendix A, is approved
   with modifications.

3. The rates and charges as set forth in Appendix C are approved as fair, just
   and reasonable rates, and these rates and charges are approved for service on and after the first day of the calendar month following the issuance of this Order.

Case No. 2021-00103, Sept. 30, 2021 Order. 422 Watson Direct Testimony at 34. 423

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1. The Joint Settlement provision regarding the Interruptible Credits is granted.
2. The depreciation study submitted by EKPC is accepted.

3. The Joint Settlement provision to amortize the RTEP Regulatory Asset over
   six years is approved.

4. The Joint Settlement provision to amortize the Deferred Smith 1 cancelation
   costs over six years is denied. The remaining balance shall be amortized through January 31, 2030.

5. The Attorney General/Nucor's recommendation to amortize the Deferred
   2019 Spurlock costs over six years is denied. The remaining balance shall be amortized at the current amortization schedule, without change.

6. The Joint Settlement provision to amortize the $27,498,249 Generation
   Maintenance Regulatory Asset over six years is approved.

7. EKPC's request to increase the Generation Maintenance Regulatory Asset
   Threshold is approved.

8. EKPC's request for rate case expenses to be amortized over a period of
   three years is approved.

9. The Joint Settlement provision regarding Adjustment Clause SEM is
   denied.

10. EKPC's request to terminate the EM is granted.

11. EKPC's original application request for the RTEP tracker is granted.

12. Except for the tariffs that have been modified or denied herein, EKPC's
    proposed stipulated tariffs are approved as filed.

13. The permanent implementation of Rate H Option B is accepted.
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14. EKPC's CAM is accepted.

15. EKPC is relieved of its annual filing requirements related to PJM
    membership but shall continue to file a report as required by Case No. 2021-00103 with its integrated resource plan (IRP) filings.

16. EKPC requested for relief from annual operating reports related to
    Bluegrass Station is granted.

17. EKPC's request to realign the filing of EKPC's small power production and
    cogeneration rates to a biennial basis is granted.

18. EKPC shall work with the special contract customer and affected Owner-
    Members to renegotiate the pumping station contract pursuant to the terms of the Joint Settlement and file any modifications to the contract within the Commission's electronic tariff filing system.

19. EKPC shall file updated interruptible credit calculations utilizing its most
    recently approved generation unit as a proxy in its next general base rate case.

20. EKPC shall continue to recover DSM costs in base rates.

21. Within 20 days of the date of service of this Order, EKPC shall file with the

Commission, using the Commission's electronic Tariff Filing System, new tariff sheets

setting forth the rates, charges, and modifications approved or as required herein and reflecting their effective date and that they were authorized by this Order.

1. This case is closed and removed from the docket. -90- Case No. 2025-00208

Entered on this 23rd day of April, 2026. PUBLIC SERVICE COMMISSION ___________________________ Angie Hatton Chair ___________________________ Mary Pat Regan Commissioner ___________________________ Andrew W. Wood Commissioner

ATTEST:

______________________ Linda C. Bridwell, PE Executive Director

APPENDIX A

FORTY-EIGHT PAGES TO FOLLOW

Page 1 of 49

COMMONWEALTH OF KENTUCKY BEFORE THE PUBLIC SERVICE COMMISSION In the Matter of: ELECTRONIC APPLICATION OF EAST KENTUCKY ) POWER COOPERATIVE, INC. FOR A GENERAL ) ADJUSTMENT OF RATES, APPROVAL OF ) CASE NO. DEPRECIATION STUDY, AMORTIZATION OF ) 2025-00208 CERTAIN REGULATORY ASSETS, AND OTHER ) OTHER GENERAL RELIEF )

JOINT STIPULATION, SETTLEMENT AGREEMENT AND RECOMMENDATION

On August 1, 2025, East Kentucky Power Cooperative, Inc. ("EKPC") tendered its Application with the Kentucky Public Service Commission ("Commission"), pursuant to KRS 278.180, KRS 278.190 and other applicable law, for an adjustment of its wholesale rates, approval of a depreciation study, amortization of certain regulatory assets and other general relief ("Application"). Motions for intervention by the Attorney General ("AG") and Nucor Steel Gallatin ("Nucor") were granted on July 10, 2025 and August 19, 2025, respectively. EKPC, the AG and Nucor are collectively referred to herein as the "Parties." The Parties have filed testimony supporting their respective positions relating to EKPC's Application. The Parties and the Commission Staff have also engaged in substantial discovery of the Parties' respective positions by issuing numerous information requests to which the Parties have responded. The Parties, representing diverse interests and viewpoints, have reached a complete settlement of all the issues raised in this proceeding and have executed this Joint Stipulation, Settlement Agreement and Recommendation ("Stipulation") for purposes of documenting and submitting their agreement to the Commission for consideration and approval. It is the intent and

purpose of the Parties to express their agreement on a mutually satisfactory resolution of all issues in the instant proceeding. The Parties understand that this Stipulation is not binding upon the Commission but believe it is entitled to careful consideration by the Commission. The Parties agree that this Stipulation, viewed in its entirety, constitutes a reasonable resolution of all issues in this proceeding. The Parties request that the Commission issue an Order approving this Stipulation in its entirety pursuant to KRS 278.190, including the rate increase, rate structure, depreciation study, amortization of regulatory assets, relief from certain existing reporting obligations, modification to several existing tariffs and recovery of rate case expense as described herein. The request is based upon the belief that the Parties' participation in settlement negotiations and the materials on file with the Commission adequately support this Stipulation. Adoption of this Stipulation will eliminate the need for the Commission and the Parties to expend significant resources in litigation of this proceeding and will eliminate the possibility of, and any need for, rehearing or appeals of the Commission's final Order herein. NOW, THEREFORE, for and in consideration of the mutual premises set forth above and the terms and conditions set forth herein, the Parties agree as follows:

1. Revenue Increase: The Parties agree that EKPC's adjusted base rate revenue
   requirement is $1,128.050 million. This represents an increase of $63.727 million over the test year revenue that would be collected at current rates. A summary of the adjustments agreed to by the Parties to arrive at this revenue increase are set forth in Exhibit A to this Stipulation.

2. Revenue Allocation. The Parties agree that that the foregoing revenue requirement
   will be allocated as follows:

3. Base Rate Times Interest Earned Ratio ("TIER") Ratio: The Parties agree that
   EKPC should be authorized to continue earning a 1.50 TIER for base rates.

4. Symmetrical Earnings Mechanism: The Parties agree that EKPC should collect or
   return any margins to its Owner-Members for contemporaneous collection or pass-through to Retail Members in the form of a bill charge or credit in the event that EKPC's per book margins fall below a 1.4 TIER or are in excess of a 1.60 TIER in any calendar year. Any margins to be collected or returned will be allocated based upon the EKPC's determination of total revenue from its Owner-Members for the most recent calendar year in total and by applicable rate classes. EKPC agrees to make an annual filing with the Commission, and provide a copy to its Owner-Members, which sets forth its calculations of margins and any required bill charge or credit for the most recent calendar year on or before February 1 of each following year. This symmetrical earnings st mechanism ("SEM") will remain in place until EKPC's base rates are next adjusted but may be renewed at that time. EKPC will file a tariff for Commission review within thirty (30) days of the Commission entering a final Order approving this Stipulation.

5. The SEM eliminates the need for the Regional Transmission Expansion
   Plan ("RTEP") deferral and generation maintenance tracker requested by EKPC and therefore EKPC withdraws its requests for them.

3 Percentage Increase in Dollars Rate Class Rate E Rate B Rate C Rate G Contract Steam Pumping Stations Total Increase 4.95% 9.64% 9.64% 9.64% 9.64% 9.64% 0.00% 5.99% $39,726,834 $63,726,019 $7,389,438 $2,917,291 $4,405,247 $1,344,423 $7,942,786 $0

1. Collection of revenue deficiencies and refund of revenue surpluses shall be
   triggered when any annual amount (or the accumulation of prior years' net amounts that were not collected/refunded) exceeds $10 million.

2. EKPC will book a regulatory asset/liability for the amount to be
   collected/returned for a year as of December 31 of that year based upon unaudited financials. st

3. EKPC will collect/refund the stated amount from/to its Owner-Members
   during a period beginning for April usage billed during May and not exceeding twelve months.

4. In the following year's filing, EKPC will make true-up adjustments to any
   changes in the SEM relating to the difference between unaudited and audited financial records; over/under collections/refunds during the current year; and any other adjustments that are necessary to assure that the SEM is accurate and correct. Any remaining liabilities/credits at the end of the final year of the accrual of a SEM amount shall be accounted for and incorporated into EKPC's next base rate case.

5. EKPC's Owner-Members will have discretion on how to best allocate a
   collection/refund of an SEM amount subject to the following:

6. Once given an allocation by EKPC, the Owner-Members will have until
   March 15 to file with the Commission a statement that sets forth the amount to be th collected/refunded for the prior year by rate class, provided, however, that an Owner-Member may choose to not refund 100% of an SEM refund from EKPC if the refund is anticipated to be needed to satisfy debt covenants or defer the filing of a rate application in the current year and the Owner Member certifies such fact to the Commission. Notwithstanding the foregoing, because of the size of the Special Contract-Large Load compared to the rest of the load of Owen Electric Cooperative and because it is its own rate class, 100% of a refund attributable to the Special Contract - Large

Load class shall be refunded. Additional details on the retail allocation of a SEM credit/charge shall be determined in tariffs approved by the Commission but the Parties agree that Owner- Members should have flexibility to develop fair, just and reasonable mechanisms that are tailored to their specific needs and interests. This should specifically include allowing a roll-in of any SEM amounts to be collected or refunded into the Owner-Member's base rates.

1. SEM collections/refunds by Owner-Members shall only be made on
   active accounts in any given billing period.

2. As with the FAC and Environmental Surcharge, the SEM formula is
   deemed a "rate" and annual changes to variables in the formula shall not be deemed a rate change. Accordingly, the Commission should not make adjustments to the proposed SEM collection/refund of either EKPC or an Owner-Member, provided, however, that the Commission shall conduct a two-year review of the operation and calculation of the SEM to assure that it has been calculated accurately and that all amounts charged/refunded are correct. In the event of any errors, the Commission shall Order a true-up to correct the miscalculation/misapplication. Nothing in this settlement is intended, or shall be construed, to limit the Commission's authority under KRS 278.260 or KRS 278.270.

3. Pumping Station Special Contract: The Parties agree that EKPC shall amend the
   25-year-old Pumping Station Special Contract to eliminate the existing subsidy by either: 1) updating transmission costs from the 2000 level and including PJM generation capacity cost in a market-based contract; or 2) place the 31.9 MW gas utility on a standard cost-of-service rate. Increased revenue from subsidy elimination will benefit EKPC and ratepayers.

4. Increase in Interruptible Credit: The Parties agree that EKPC shall increase the
   interruptible credit by $2.00/KW-month for its 28 existing and new interruptible customers

because of increased cost of new CT generation and significantly increased value of capacity in PJM. The interruptible credits for Special Contract-Large Load have not been increased since

2011.

1. Other Items: The Parties agree that, except as limited herein, all other requests in
   EKPC's Application should be approved, including, without limitation:

2. Depreciation Study: Except as noted in the removal of terminal net salvage
   from fossil generation in the revenue requirement, EKPC's proposed depreciation study and related accounting treatments should be approved with an effective date for the new deprecation rates to be the same day that EKPC's new rates become effective.

3. Amortization of Certain Regulatory Assets: The three regulatory assets
   identified in EKPC's Application are acknowledged to be included within its revenue requirement and will be approved as proposed:

4. Extending the amortization for the cancellation of the Smith Unit 1
   generation station that was authorized in Case No. 2010-00449, and consistent with the provisions of the Stipulation Agreement approved in Case No. 2015-00358, for 6 years;

5. Amortizing the Generation Maintenance regulatory asset for 6
   years; and

6. Amortizing the RTEP regulatory asset that was approved by the
   Commission in Case No. 2025-00193 for 6 years.

7. Relief From Certain Existing Reporting Obligations: EKPC should no
   longer be required to make certain informational filings with the Commission that appear to be obsolete:

8. Annual comprehensive report identifying benefits and costs that
   accrue from its PJM Interconnection, LLC ("PJM") membership and comparing these to benefits and costs if EKPC left PJM as modified in Case No. 2021-00103 and originally from Case No. 2012-00169; and,

9. Annual operating reports setting forth details of the performance
   of the Bluegrass Station from Case No. 2015-00267.

10. PURPA Tariff Updates: The Parties agree that EKPC's request to realign
    the filing of its small power production and cogeneration rates to a biennial basis in accordance with 807 KAR 5:054.

11. Tariff Changes: The Parties agree all proposed modifications to EKPC's
    tariffs should be approved as set forth in the Application.

12. Rate Case Expense: The Parties agree that EKPC should be authorized to
    recover its reasonable rate case expense, including the amounts for its Owner-Members' pass- through cases, (final amount to be filed within fifteen days following the conclusion of any hearing on EKPC's Application) on an amortized basis over three (3) years.

13. Stay-Out: EKPC agrees to a minimum three-year rate case stay-out.
    EKPC cannot have new base rates become effective for three years from the date of approval of this Settlement, however, EKPC may file a rate case prior to that date such that the effective date for the rates fulfills the minimum three-year requirement. New base rates will become effective not later than six years after the rates established in this case become effective. To maintain EKPC's credit metrics during the $2 billion capital plan, the Parties agreed to implement the SEM discussed above and the SEM is a material element of this Stipulation. Notwithstanding the

base rate stay-out commitment described above, EKPC shall retain the right, at any time, to seek approval from the Commission of:

1. The deferral of costs as permissible under the Commission's
   standard for deferrals, including:

2. An extraordinary, nonrecurring expense which could not
   have reasonably been anticipated or included in the utility's planning;

3. An expense resulting from a statutory or administrative
   directive;

4. An expense in relation to an approved industry initiative; or

5. An extraordinary or nonrecurring expense that over time will
   result in a savings that fully offsets the cost.

6. Emergency rate relief under KRS 278.190(2) to avoid a material
   impairment or damage to credit or operations;

7. Adjustments to the operation of any of EKPC's now existing, or
   future, cost recovery surcharge mechanisms (e.g., Fuel Adjustment Clause, Environmental Surcharge, Symmetrical Earnings Mechanism, etc.,); and

8. During the effective stay-out period, EKPC reserves the right to seek
   necessary rate relief and/or accounting treatment for costs or programs required due to changes in law or regulations, including but not limited to, changes in tax rates, or changes to existing, or implementation of new, environmental (e.g. federal or state EPA rules) or safety compliance costs applicable to generation and transmission cooperatives that may occur during the stay-out period.

9. Proof of Revenue: Attached to this Stipulation as Exhibit B are updated
   tariffs that reflect the revenue requirement and revenue allocation set forth herein. Attached to

this Stipulation as Exhibit C are proof-of-revenue sheets, showing that the rates set forth in Exhibit B, plus projected off-system sales, leased property income and other operating revenues, will generate the revenue needed to recover the Company's test year revenue requirement to which the Parties have agreed.

1. Filing of Stipulation: Following the execution of this Stipulation, the Parties shall
   cause the Stipulation to be filed with the Commission with a request to the Commission for consideration and approval of this Stipulation so that EKPC may begin billing under the approved adjusted rates for service rendered on and after February 1, 2026.

2. Commission Approval: The Parties to this Stipulation shall act in good faith and
   use their best efforts to recommend to the Commission that this Stipulation be accepted and approved. Each Party hereto waives all cross-examination of the witnesses of the other Party hereto except in support of the Stipulation or unless the Commission fails to adopt this Stipulation in its entirety. Each Party further stipulates and recommends that the Notice of Intent, Notice, Application, direct testimony, rebuttal testimony, pleadings and responses to data requests filed in this proceeding be admitted into the record. The Parties further agree and intend to support the reasonableness of this Stipulation before the Commission, and to cause their counsel and witnesses to do the same in this proceeding and in any appeal from the Commission's adoption and/or enforcement of this Stipulation. If the Commission issues an order adopting this Stipulation in its entirety, each of the Parties hereto agrees that it shall file neither an application for rehearing with the Commission, nor an appeal to the Franklin County Circuit Court with respect to such order.

3. Effect of Non-Approval: If the Commission does not accept and approve this
   Stipulation in its entirety or imposes any additional conditions or requirements upon the signatory Parties, then: (a) any adversely affected Party may elect, in writing docketed in this proceeding,

within ten (10) days of such Commission Order, that this Stipulation shall be void and withdrawn by the Parties hereto from further consideration by the Commission and no Party shall be bound by any of the provisions herein; and (b) each Party shall have the right, within twenty (20) days of the Commission's Order, to file a petition for rehearing, including a notice of termination of and withdrawal from the Stipulation; and, (c) in the event of such termination and withdrawal of the Stipulation, neither the terms of this Stipulation nor any matters raised during the settlement negotiations shall be binding on any of the signatory Parties to this Stipulation or be construed against any of the signatory Parties. Should the Stipulation be voided or vacated for any reason after the Commission has approved the Stipulation and thereafter any implementation of the terms of the Stipulation has been made, then the Parties shall be returned to the status quo existing at the time immediately prior to the execution of this Stipulation.

1. Commission Jurisdiction: This Stipulation shall in no way be deemed to divest the
   Commission of jurisdiction under Chapter 278 of the Kentucky Revised Statutes.

2. Successors and Assigns: This Stipulation shall inure to the benefit of and be binding
   upon the Parties hereto, their successors and assigns.

3. Complete Agreement: This Stipulation constitutes the complete agreement and
   understanding among the Parties hereto, and any and all oral statements, representations or agreements made prior hereto or contained contemporaneously herewith shall be null and void and shall be deemed to have been merged into this Stipulation.

4. Implementation of Stipulation: For the purpose of this Stipulation only, the terms
   are based upon the independent analysis of the Parties to reflect a just and reasonable resolution of the issues herein and are the product of compromise and negotiation. Notwithstanding anything contained in the Stipulation, the Parties recognize and agree that the effects, if any, of any future

events upon the operating income of EKPC are unknown, and this Stipulation shall be implemented as written.

1. Admissibility and Non-Precedential Effect: Neither the Stipulation nor any of the
   terms set forth herein shall be admissible in any court or administrative agency, including the Commission, except insofar as such court or agency is addressing litigation arising out of the implementation of the terms herein or the approval of this Stipulation. This Stipulation shall not have any precedential value in this or any other jurisdiction.

2. No Admissions: Making and entering into this Stipulation shall not be deemed in
   any respect to constitute an admission by any Party that any computation, formula, allegation, assertion or contention made by any Party in these proceedings is true or valid. Nothing in this Stipulation shall be used or construed for any purpose to imply, suggest or otherwise indicate that the results produced through the compromise reflected herein represent fully the objectives of a Party.

3. Authorizations: The signatories hereto warrant that they have informed, advised,
   and consulted with the respective Parties hereto in regard to the contents of this Stipulation, and based upon the foregoing, are authorized to execute this Stipulation on behalf of the Parties hereto.

4. Commission Approval: This Stipulation is subject to the acceptance of and approval
   by the Commission. 18 Interpretation of Stipulation: This Stipulation is a product of negotiation among all Parties hereto, and no provision of this Stipulation shall be strictly construed in favor of or against any Party.

5. Counterparts: This Stipulation may be executed in multiple counterparts.

6. Future Proceedings: Nothing in this Stipulation shall preclude, prevent or prejudice
   any Party hereto from raising any argument/issue or challenging any adjustment in any future rate case proceeding of EKPC. IN WITNESS WHEREOF, this Stipulation has been agreed to and is effective as of this 24 day of November 2025. By affixing their signatures below, the undersigned Parties th respectfully request the Commission to issue its Order approving and adopting this Stipulation the Parties hereto have hereunto affixed their signatures.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

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Exhibit A Summary of Revenue Adjustments

(Millions)

Costs to Amortize Existing Balance over Six Years

Also, please see the Exhibit A Excel Spreadsheet filed separately.

Reduce Amortization Expense for Deferred Smith Unit 1 Cancellation ($9.609) Amount Description

Adjust Generation Maintenance Expense Based on a Five-Year Average ($4.583) ($2.368) ($2.559) ($0.248) ($0.025) $79.757 $63.727 $3.361 Adjusted Revenue Requirement Calculation Agreed to by Parties Reduce Depreciation Expense to Remove Terminal Net Salvage Remove Amortization Expense Associated with 2021 Rate Case Original Revenue Requirement Calculated by EKPC Amortize Generation Maintenance over Six Years Amortize RTEP Regulatory Asset over Six Years PSC Assessment Fee

Exhibit B Revised Tariff Sheets

P.S.C. No. 35, Third Revised Sheet No. 5 Canceling P.S.C. No. 35, Second Revised Sheet No. 5 Rate B In all territories of owner-member cooperatives ("owner-members") of East Kentucky Power Cooperative, Inc. ("EKPC").

Available to owner-members and end-use retail members ("retail members") willing to execute EKPC- approved contracts for demands of 500 kW or greater and a monthly minimum energy usage equal to or greater than 400 hours per kW of contract demand. Wholesale monthly contract demand shall be agreed upon between the owner-member and EKPC. Any changes to contract demand between the owner- member and EKPC shall be limited to two (2) per year. The electric power and energy furnished hereunder shall be separately metered for each point of delivery. Demand Charge per kW of Contract Demand $9.39 Demand Charge per kW of Billing Demand in $12.53 Excess of Contract Demand Energy Charge per kWh $0.054560 The billing demand shall be the contract demand plus any excess demand. Excess demand occurs when the retail member's highest demand during the current month, coincident with EKPC's system peak (coincident peak), exceeds the contract demand. EKPC's system peak demand is the highest average rate at which energy is used during any fifteen (15)-minute interval in the below listed hours for each month and adjusted for power factor as provided herein:

1. The product of the contract demand multiplied by the demand charge, plus
2. The product of the contract demand multiplied by 400 hours and the energy charge per kWh T I Months

P.S.C. No. 35, Third Revised Sheet No. 7 Canceling P.S.C. No. 35, Second Revised Sheet No. 7 Rate C

Available to owner-members and retail members willing to execute EKPC-approved contracts for demands of 500 kW or greater and a monthly minimum energy usage equal to or greater than 400 hours per kW of billing demand. The electric power and energy furnished hereunder shall be separately metered for each point of delivery. Demand Charge per kW of Billing Demand $9.32 Energy Charge per kWh $0.054460

1. The product of the billing demand multiplied by the demand charge, plus
2. The product of the billing demand multiplied by 400 hours and the energy charge per kWh I I Months

P.S.C. No. 35, Third Revised Sheet No. 9 Canceling P.S.C. No. 35, Second Revised Sheet No. 9 Rate E

Available to all owner-members of EKPC for all power usage at the load center not subject to the provisions of Rate B, Rate C, or Rate G of this tariff and special contract participants. The electric power and energy furnished hereunder shall be separately metered for each point of delivery. Monthly Rate - Per Load Center An owner-member may select either Option 1 or Option 2 of this section of the tariff to apply to all load centers. The owner-member must remain on a selected option for at least one (1) year and may change

options, no more often than every twelve (12) months, after giving a minimum notice of two (2) months l advance notice of an election to change options.

On-peak and off-peak hours are provided below:

I $0.064916 Option 1 Option 2 On-Peak kWh $0.055860 10:00 p.m. to 7:00 a.m. Off-Peak Hours - EPT On-Peak Hours - EPT Months $9.60 $7.37 Off-Peak kWh $0.055307 $0.055875 10:00 p.m. to 10:00 a.m. 12:00 noon to 5:00 p.m.

P.S.C. No. 35, Third Revised Sheet No. 12 Canceling P.S.C. No. 35, Second Revised Sheet No. 12 Rate G SPECIAL ELECTRIC CONTRACT RATE

Available to all owner-members and retail members willing to execute EKPC-approved contracts. The electric power and energy furnished hereunder shall be separately metered for each point of delivery.

Demand Charge per kW of Billing Demand $8.91 Energy Charge per kWh $0.052044 Determination of Billing Demand

I I Hours Applicable for Demand Billing - EPT Months

P.S.C. No. 35, Second Revised Sheet No. 15 Canceling P.S.C. No. 35, First Revised Sheet No. 15 In all territories of owner-members of EKPC.

This rate schedule shall apply to all rates in this tariff and to each EKPC load center separately. Load Center Charges - Monthly

1. Metering Point Charge
2. Applicable to each metering point and to each substation.
3. Charge: $159.00
4. Substation Charge
5. Applicable to each substation based on its size.
6. Charges: The minimum monthly charge shall be equal to the Load Center Charges plus the minimum monthly charges for Rates B, C and G. Load Center Charges cover metering point and substation charge.

15,000 and over kVa substation 7,500 - 14,999 kVa substation 1,000 - 2,999 kVa substation $1,200.00 $3,629.00 $5,854.00 3,000 - 7,499 kVa substation $3,018.00 I I

P.S.C. No. 35, Third Revised Sheet No. 23 Canceling P.S.C. No. 35, Second Revised Sheet No. 23 Rate D Interruptible Service This Interruptible Rate is a rider to Rates B, C, E, and G.

This rate shall be made available at any load center, to any owner-member where a retail member will contract for an interruptible demand of not less than 250 kW, subject to a maximum number of hours of interruption per year and a notice period as listed below. Note that hours of interruption per year or annual hours of interruption refer to the twelve (12)-month period ended May 31.

A monthly interruptible demand credit per kW is based on the following matrix:

The billing demand shall be determined as defined in to Rates B, C, E, or G as applicable. The firm demand shall be the retail member's minimum level of demand needed to continue operations during an interruption. The firm demand shall not be subject to interruption and shall be specified in the contract. The interruptible demand shall be equal to the amount by which the monthly billing demand exceeds the

$7.60 $6.20 $6.90 I D D Notice of Minutes Annual Hours of Interruption

P.S.C. No. 35, Third Revised Sheet No. 24 Canceling P.S.C. No. 35, Second Revised Sheet No. 24 Conditions of Service for Customer

1. The retail member will, upon notification by EKPC, reduce the load being supplied by the
   owner-member to the firm demand specified by the contract.

2. EKPC will endeavor to provide the retail member as much advance notice as possible of the
   interruption of service. However, the retail member shall interrupt service within the notice period as contracted.

3. Service will be furnished under the owner-member's "General Rules and Regulations" or
   "Terms and Conditions" except as set out herein and/or provisions agreed to by written contract.

4. No responsibility of any kind shall attach to EKPC and/or the owner-member for, or on account
   of, any loss or damage caused by, or resulting from, any interruptions or curtailment of this service.

5. The retail member shall own, operate, and maintain all necessary equipment for receiving
   electric energy and all telemetering and communications equipment, within the retail member's premises, required for interruptible service.

6. The minimum original contract period shall be one-year and thereafter until terminated by giving
   at least sixty (60)-days previous written notice. EKPC may require a contract be executed for a longer initial term when deemed necessary by the size of the load and other conditions. Calculation of Monthly Bill The monthly bill is calculated as follows:

7. The demand and energy charges of the bill shall be calculated consistent with the applicable
   provisions of Rates B, C, E, or G.

8. The interruptible demand credit shall be determined by multiplying the interruptible demand for
   the billing month by the monthly demand credit per kW and applied to the bill calculation.

9. All other applicable bill riders, including the Fuel Adjustment Clause and Environmental
   Surcharge, shall be applied to the bill calculation consistent with the provisions of those riders.

P.S.C. No. 35, Third Revised Sheet No. 25 Canceling P.S.C. No. 35, Second Revised Sheet No. 25 Number and Duration of Interruptions

1. There shall be no more than two (2) interruptions during any 24-hour calendar day. No
   interruption shall last more than twelve hours.

2. The maximum number of annual hours of interruption shall be in accordance with the retail
   member-contracted level of interruptible service. Charge for Failure to Interrupt lf the retail member fails to interrupt its demand as requested by EKPC, the owner-member shall bill the uninterrupted demand at a rate equal to five (5) times the applicable firm power demand charge for that billing month. Uninterrupted demand is equal to actual demand during the requested interruption minus

P.S.C. No. 35, Third Revised Sheet No. 35 Canceling P.S.C. No. 35, Second Revised Sheet No. 35 Rate H Wholesale Renewable Energy Program This Renewable Energy Program is a rider to Rates B, C, E and G. The purpose of this program is to provide EKPC owner-members with a source of renewable energy or renewable energy attributes for resale to their retail members.

1. "Renewable energy" is that electricity which is generated from renewable sources including but not
   limited to: solar, wind, hydroelectric, geothermal, landfill gas, biomass, biodiesel used to generate electricity, agricultural crops or waste, all animal and organic waste, all energy crops and other renewable certified resources.

2. A "Renewable Energy Certificate" ('REC') is the tradable renewable energy attribute which
   represents the commodity formed by unbundling the environmental-benefit attributes of a unit of renewable energy from the underlying electricity. One REC is equivalent to the environmental- benefits attributes of one MWh of renewable energy. Availability of Service Option A: Owner-members may participate in the program by contributing monthly as much as they like in $2.50 increments (e.g. $2.50, $5.00, $7.50, or more per month). Funds provided by owner-members are not refundable. Option B: Owner-members may, after entering into an agreement with their retail member and EKPC, offer renewable energy to offset a portion or all of the energy consumed by the retail member utilizing owner- member's firm service rates. Option C: Owner-members may participate in this REC program, after entering into an agreement with their commercial and industrial ("C&l') retail member, by offering the C&l retail members the opportunity to purchase RECs through their owner-member and EKPC to offset up to all of their energy consumption with RECs, resulting in that portion of energy consumed to be considered renewable.

P.S.C. No. 35, Third Revised Sheet No. 36 Canceling P.S.C. No. 35, Second Revised Sheet No. 36 Eligibility All EKPC owner-members are eligible for this rider. Under Option A, the owner-member will indicate the amount of voluntary Renewable Energy Program Contributions that the owner-member intends to purchase monthly. All owner-members will have executed a Renewable Energy Program Agreement with the participating retail member. Under Option B, the retail member in conjunction with the owner-member and EKPC, will determine the amount of renewable energy to be provided to the retail member. The minimum renewable energy capacity to be purchased, supplied, or secured by EKPC in the agreement should be 1 MW. The maximum annual renewable energy under the agreement can't exceed the participating retail member's average annual consumption over the previous three (3) years. For new businesses with no usage history, the maximum annual renewable energy under the contract will be estimated. The type of renewable energy will be selected by individually participating retail members. Retail members having multiple services across the EKPC system may aggregate consumption and renewable energy totals into a single agreement. Under Option C, C&l retail members, in conjunction with the owner-member and EKPC, will determine the type of renewable resource and number of RECs the owner-member and EKPC will purchase monthly on behalf of the participating retail member. The original agreement will expire after one (1) year, but will automatically renew monthly until the retail member provides 60 days' notice of cancellation. The retail member may also amend the agreement to change the number of RECs or the type of renewable resource generating such RECs they will purchase. EKPC may sell and retire RECs generated by EKPC when applicable with a market-based rate per REC. The sum of renewable energy purchased under Option B and RECs purchased and retired under Option C shall not exceed the customer's annual usage.

Option A Renewable Energy Program Contributions: The monthly Renewable Energy Program Contributions by the owner-member is the total monthly voluntary contribution by the owner-member's participating retail members in any $2.50 increments for the type of renewable energy resources (Landfill Gas, Solar, Wind, Hydroelectric) chosen by the participating retail member. EKPC will generate, purchase renewable energy, or purchase RECs equal to the monthly sum of Renewable Energy Program Contributions for each renewable energy resource type minus $0.25 per increment retained to help offset administrative and advertising costs. For Renewable Energy Program Contributions assigned by the retail member for renewable energy resources that EKPC does not own, EKPC will purchase the appropriate type of RECs equaling the total contribution amount and will retire the associated RECs. For Renewable Energy Program Contributions assigned by the retail member for renewable energy resources that EKPC owns and operates, EKPC will allocate the appropriate generation (kwhs) and costs to the assigned renewable energy program contribution and retire the associated RECs.

T/D T/D

P.S.C. No. 35, Third Revised Sheet No. 37 Canceling P.S.C. No. 35, Second Revised Sheet No. 37 Option C Participating C&l retail members will pay the market value of the RECs purchased on their behalf without markup from the owner-member or EKPC. They will have the option to instruct the owner-member and EKPC to purchase: (i) RECs covering a set percentage of their energy consumption each month; (ii) a set dollar amount of RECs per month; or (iii) a set number of MWhs. The participating C&l retail member can set a REC price that requires additional approvals for EKPC to purchase RECs per the Agreement. EKPC will act as the participating retail member's REC purchasing agent including settling the REC market transactions and REC retirements

Under Option A, EKPC will bill the owner-member at the rate of $2.50 per increment. The sum of the Renewable Energy Program Contributions from each renewable energy resource type pledged under this tariff shall constitute the total amount that the owner-member may be billed during a normal billing period. Existing Wholesale Renewable Energy Program ("Envirowatts") retail participants will be billed at the existing retail rate from their owner-member. Under Option B, EKPC will increase the owner-member monthly wholesale power bill by the negotiated and contracted renewable energy rate and delivered renewable energy for each participating agreement while providing a credit for the avoided cost of base fuel per MWh of renewable energy delivered and capacity credits when applicable. Under Option C, EKPC will increase the owner-member monthly wholesale bill for the RECs purchased at the market price plus a monthly transactional fee of $100 and incurred volumetric fees. Volumetric fees include per REC costs paid directly to other parties by EKPC to procure specific types of RECs, (ie. Green- Energy certified RECs) and per REC costs paid directly to other parties by EKPC to retire RECs via e® industry recognized renewable attribute registries. For any agreement instructing EKPC to purchase RECs in advance of the billing cycle, a monthly carrying charge equal to 1112 of the annual short-term borrowing rate will be added to the participant's bill. Terms of Service and Payment This rate shall be subject to all other terms of service and payment of the wholesale power tariff.

P.S.C. No. 35, Third Revised Sheet No. 38 Canceling P.S.C. No. 35, Second Revised Sheet No. 38 Fuel Adjustment Clause Under Options A and C, the fuel adjustment clause is not applicable to the Renewable Energy Program Contributions. Under Option B, EKPC will provide a credit on the owner-member's monthly wholesale power bill for the avoided cost of the base fuel and the Fuel Adjustment Clause equal to the delivered renewable energy monthly for each participating agreement. Environmental Surcharge Under Options A and C, the environmental surcharge is not applicable to the Renewable Energy Program Contributions. Under Option B, EKPC will provide a credit on the owner-member's monthly wholesale power bill for the avoided cost of the variable environmental surcharge equal to the delivered renewable energy monthly for each participating agreement. Total Credits Under Option B, the total credit on the owner-member's monthly wholesale power bill will be the total of the avoided costs from base fuel, the fuel adjustment clause, capacity credits when applicable, and the variable environmental surcharge for the delivered renewable energy. The total credit will be limited to the lesser of the total credit as described in the Fuel Adjustment Clause and Environmental Surcharge sections above or the PJM Localized Marginal Cost ("LMP").

P.S.C. No. 35, Second Revised Sheet No. 47 Cancelling P.S.C. No. 35, First Revised Sheet No. 47

Rate SEM Symmetrical Earnings Mechanism

This Symmetrical Earnings Mechanism is a rider to Rates B, C, DCP, E, and G, as well as applicable to all special contract customers.

ln all territories of Owner-Member Cooperatives ("Owner-Member") of EKPC.

Available to Owner-Members and End-Use Retail Members ("Retail Member"), except for any End-Use Retail Member taking service under Rate DCP Attachment A, as of the date of the issuance of a credit or debit pursuant to Paragraph 4 of the Joint Stipulation, Settlement Agreement and Recommendation approved in Case No. 2025-00208. Purpose EKPC has committed to collect or return any margins to its Owner-Members for contemporaneous collection or refund to Retail Members in the form of a bill charge or credit in the event that EKPC's per book margins fall below a 1.40 TIER or are in excess of a 1.60 TIER in any calendar year. Any margins to be collected or returned will be allocated based upon the percentage of each EKPC rate class's total revenue for the most recent calendar year. EKPC will make an annual filing with the Commission setting forth its calculations of margins and any required bill charge or credit for the most recent calendar year on or before February 1st of the following year. Also included in the annual filing will be a true-up of any difference between EKPC's audited and unaudited financials, over/under collections/refunds during the current year, and any other adjustments that are necessary to assure that the SEM is accurate and correct.

Methodology Excess Margins. EKPC will determine any excess margins for the most recent calendar year by comparing the per book margins reflected in the achieved TIER with the margins needed to produce a 1.60 TIER. If the margins reflected in the achieved TIER exceed the margins needed to produce a 1.60 TIER, then the dollar difference in the margins will constitute excess margins to return to the Owner-Members and Retail Members. lf the margins needed to produce a 1.60 TIER exceeds the margins reflected in the achieved TIER, then there will be no excess margins returned for the calendar year.

P.S.C. No. 35, Second Revised Sheet No. 47.1 Cancelling P.S.C. No. 35, First Revised Sheet No. 47.1 Deficient Margins. EKPC will determine any deficient margins for the most recent calendar year by comparing the per book margins reflected in the achieved TIER with the margins needed to produce a 1.4 TIER. If the margins reflected in the achieved TIER are less than the margins needed to produce a 1.4 TIER, then the dollar difference in the margins will constitute deficient margins to collect from the Owner- Members and Retail Members. If the margins needed to produce a 1.4 TIER are less than the margins reflected in the achieved TIER, then there will be no deficient margins to collect for the calendar year. Minimum Excess/Deficient Margin. Any calculated Excess/Deficit Margin will be recorded annually as a regulatory liability/asset. EKPC will not refund/collect any Excess/Deficit Margin until the cumulative balance meets or exceeds $10 million. In the final year of operation under this tariff, any remaining Excess/Deficit Margin shall be refunded/collected regardless of amount. Large Special Contract Consideration If an Excess Margin is incurred, Owen Electric Cooperative's Large Special Contract customer will receive the excess margin allocated to that class during the calendar year that the Excess Margin is passed from EKPC to the Owner-Member. Allocation of Excess or Deficient Margins. EKPC will determine its total revenues from its Owner-Members for the most recent calendar year in total and by applicable rate classes. For purposes of this calculation,

1. EKPC's rate classes are tariffed Rates B, C, E, and G and special contracts not based on tariffed
   rate schedules; and

2. EKPC's Rate E total revenues will include the solar panel production credits, green power billing,
   direct load control credits, and the generator credit; and

3. Any customer under EKPC's Rate Data Center Power (Rate DCP) will not be subject to any
   allocation of Excess or Deficient Margins if they are taking service under Attachment A of Rate DCP - Dedicated Resource Rider.

P.S.C. No. 35, Original Sheet No. 47.2 The allocation of the Excess or Deficient Margin for the most recent calendar year will be performed using a two-step process. EKPC will first determine the percentage of total revenues each of its rate classes represent. The Excess or Deficient Margin will be multiplied by this rate class percentage of total revenues to determine the allocation of the Excess or Deficient Margin by rate class. If the rate class only has one retail member, then no further allocation will be necessary. For all other rate classes, EKPC will next determine the percentage of each rate class revenues provided by the Owner-Members. The allocated Excess or Deficient Margin by rate class's will be multiplied by the applicable Owner-Member percentage for that rate class to determine the allocation of the Excess or Deficient Margin by rate class by Owner- Member. EKPC will prepare and provide to each Owner-Member a schedule showing the allocation of the Excess or Deficient Margin for the most recent calendar year by EKPC rate class by February 1st. Each Owner-Member will utilize this schedule to then determine the bill credit or debit that will correspond to the Excess or Deficient margins to their Retail Members in a manner consistent with the Stipulation approved by the Commission in Case No. 2025-00208. The Owner-Members will have flexibility in determining the manner to allocate the Excess or Deficient Margins to their Retail Members, including as a roll-in to base rates, and may also retain the excess margins to meet a debt covenant or defer the filing of a rate case in the current year. Payment(s) of Bill Credit or Collection of Deficient Margins. EKPC will include the applicable bill credit or debit to each Owner-Member on the billing invoices issued in a time period beginning no earlier than April usage billed in May and not to exceed twelve (12) months. Annual True-Ups. At the end of a calendar year, EKPC shall include in the following year's February 1 st filing the net of any amounts (positive or negative) equal to: (1) the difference between the prior year's per book margin and its final audited margin; (2) over/under collections from the current year; and (3) other adjustments that are necessary to assure that the amounts collected/refunded are correct and accurate. Commission Review. The mechanism described herein is the "rate" for purposes of Kentucky law and the annual calculation and schedule of amounts to be collected/refunded in accordance with this tariff shall not be considered a change in rates. Nevertheless, Commission shall review the operation and effect of the tariff every two-years. Such reviews shall assure that Rate SEM has been correctly calculated and that all amounts charged/refunded are correct. In the event of any errors, the Commission shall order a true-up to correct the miscalculation or misapplication. Nothing in this tariff shall be construed to limit in any way the Commission's authority under KRS 278.260 and KRS 278.270.

cond Third Revised Sheet No. 5 Canceling P.S.C. No. 35, First Second Revised Sheet No. 5 Rate B In all territories of owner-member cooperatives ("owner-members") of East Kentucky Power Cooperative, Inc. ("EKPC").

Available to owner-members and end-use retail members ("retail members") willing to execute EKPC- approved contracts for demands of 500 kW or greater and a monthly minimum energy usage equal to or greater than 400 hours per kW of contract demand. Wholesale monthly contract demand shall be agreed upon between the owner-member and EKPC. Any changes to contract demand between the owner- member and EKPC shall be limited to two (2) per year. The electric power and energy furnished hereunder shall be separately metered for each point of delivery. Demand Charge per kW of C ontract Demand $7.49 $9.39 Demand Charge per kW of Billing Demand in $9.98 $12.53 Excess of Contract Demand $ .051134 $0.054560 The billing demand shall be the contract demand plus any excess demand. Excess demand occurs when the retail member's highest demand during the current month, coincident with EKPC's system peak (coincident peak), exceeds the contract demand. EKPC's system peak demand is the highest average rate at which energy is used during any fifteen (15)-minute interval in the below listed hours for each month and adjusted for power factor as provided herein:

1. The product of the contract demand multiplied by the demand charge, plus
2. The product of the contract demand multiplied by 400 hours and the energy charge per kWh of Kentucky in Case No. 2023 -00009 2025-00208 dated May 6, 2024 __, _ 2026.

T I Months

cond Third Revised Sheet No. 7 Canceling P.S.C. No. 35, First Second Revised Sheet No. 7 Rate C

Available to owner-members and retail members willing to execute EKPC-approved contracts for demands of 500 kW or greater and a monthly minimum energy usage equal to or greater than 400 hours per kW of billing demand. The electric power and energy furnished hereunder shall be separately metered for each point of delivery. Demand Charge per kW of Billing Demand $7.49 $9.32 Energy Charge per kWh $ .051134 $0.054460

1. The product of the billing demand multiplied by the demand charge, plus
2. The product of the billing demand multiplied by 400 hours and the energy charge per kWh I I Months

cond Third Revised Sheet No. 9 Canceling P.S.C. No. 35, First Second Revised Sheet No. 9 Rate E

Available to all owner-members of EKPC for all power usage at the load center not subject to the provisions of Rate B, Rate C, or Rate G of this tariff and special contract participants. The electric power and energy furnished hereunder shall be separately metered for each point of delivery. r Load Center Monthly Rate - Pe An owner-member may select either Option 1 or Option 2 of this section of the tariff to apply to all load centers. The owner-member must remain on a selected option for at least one (1) year and may change

options, no more often than every twelve (12) months, after giving a minimum notice of two (2) months

advance notice of an election to change options. l

On-peak and off-peak hours are provided below:

I $ .062649 $0.064916 Option 1 Option 2 On-Peak kWh $ .053841 $0.055860 10:00 p.m. to 7:00 a.m. Off-Peak Hours - EPT On-Peak Hours - EPT Months $8.49 $9.60 $6.52 $7.37 Off-Peak kWh $ .053263 $0.055307 $ .053924 $0.055875 10:00 p.m. to 10:00 a.m. 12:00 noon to 5:00 p.m.

cond Third Revised Sheet No. 12 Canceling P.S.C. No. 35, First Second Revised Sheet No. 12 Rate G SPECIAL ELECTRIC CONTRACT RATE

Available to all owner-members and retail members willing to execute EKPC-approved contracts. The electric power and energy furnished hereunder shall be separately metered for each point of delivery.

Demand Charge per kW of B illing Demand $7.30 $8.91 Energy Charge per kWh $ .049030 $0.052044 Determination of Billing Demand

of Kentucky in Case No. 2023-00009 2025-00208 dated May 6, 2024 __, _ 2026.

I I Hours Applicable for Demand Billing - EPT Months

P.S.C. No. 35, First Seco nd Revised Sheet No. 15 Canceling P.S.C. No. 35, Original First Revised Sheet No. 15 In all territories of owner-members of EKPC.

This rate schedule shall apply to all rates in this tariff and to each EKPC load center separately. nthly Load Center Charges - Mo

1. Metering Point Charge
2. Applicable to each metering point and to each substation.
3. Charge: $151.20 $ 159.00
4. Substation Charge
5. Applicable to each substation based on its size.
6. Charges: The minimum monthly charge shall be equal to the Load Center Charges plus the minimum monthly charges for Rates B, C and G. Load Center Charges cover metering point and substation charge.

15,000 and over kVa substation 7,500 - 14,999 kVa substation 1,000 - 2,999 kVa substation $1,142.40 $1,200.00 $3,456.60 $3,629.00 $5.575.50 $5,854.00 3,000 - 7,499 kVa substation $2,873.85 $3,018.00 I I

cond Third Revised Sheet No. 23 Canceling P.S.C. No. 35, First Second Revised Sheet No. 23 Rate D Interruptible Service This Interruptible Rate is a rider to Rates B, C, E, and G.

This rate shall be made available at any load center, to any owner-member where a retail member will contract for an interruptible demand of not less than 250 kW and not more than 20,000 kW, subject to a maximum number of hours of interruption per year and a notice period as listed below. Note that hours of interruption per year or annual hours of interruption refer to the twelve (12)-month period ended May 31.

A monthly interruptible demand credit per kW is based on the following matrix:

The billing demand shall be determined as defined in to Rates B, C, E, or G as applicable. The firm demand shall be the retail member's minimum level of demand needed to continue operations during an interruption. The firm demand shall not be subject to interruption and shall be specified in the contract. The interruptible demand shall be equal to the amount by which the monthly billing demand exceeds the firm demand, up to 20,000 kW maximum.

$5.60 $7.60 $4.20 $6.20 $4.90 $6.90 D D I Notice of Minutes Annual Hours of Interruption

cond Third Revised Sheet No. 24 Canceling P.S.C. No. 35, First Second Revised Sheet No. 24 Conditions of Service for Customer

1. The retail member will, upon notification by EKPC, reduce the load being supplied by the
   owner-member to the firm demand specified by the contract.

2. EKPC will endeavor to provide the retail member as much advance notice as possible of the
   interruption of service. However, the retail member shall interrupt service within the notice period as contracted.

3. Service will be furnished under the owner-member's "General Rules and Regulations" or
   "Terms and Conditions" except as set out herein and/or provisions agreed to by written contract.

4. No responsibility of any kind shall attach to EKPC and/or the owner-member for, or on account
   of, any loss or damage caused by, or resulting from, any interruptions or curtailment of this service.

5. The retail member shall own, operate, and maintain all necessary equipment for receiving
   electric energy and all telemetering and communications equipment, within the retail member's premises, required for interruptible service.

6. The minimum original contract period shall be one-y ear and thereafter until terminated by giving
   at least sixty (60)-days previous written notice. EKPC may require a contract be executed for a longer initial term when deemed necessary by the size of the load and other conditions. Calculation of Monthly Bill The monthly bill is calculated as follows:

7. The demand and energy charges of the bill shall be calculated consistent with the applicable
   provisions of Rates B, C, E, or G.

8. The interruptible demand credit shall be determined by multiplying the interruptible demand for
   the billing month by the monthly demand credit per kW and applied to the bill calculation.

9. All other applicable bill riders, including the Fuel Adjustment Clause and Environmental
   Surcharge, shall be applied to the bill calculation consistent with the provisions of those riders.

cond Third Revised Sheet No. 25 Canceling P.S.C. No. 35, First Second Revised Sheet No. 25 Number and Duration of Interruptions

1. There shall be no more than two (2) interruptions during any 24-hour calendar day. No
   interruption shall last more than twelve hours.

2. Interruptions may occur between 6:00 a.m. and 9:00 p.m. EPT during the months of November
   through April and between 10:00 a.m. and 10:00 p.m. during the months of May through October.

3. The maximum number of annual hours of interruption shall be in accordance with the retail
   member-contracted level of interruptible service. Charge for Failure to Interrupt lf the retail member fails to interrupt its demand as requested by EKPC, the owner-member shall bill the uninterrupted demand at a rate equal to five (5) times the applicable firm power demand charge for that billing month. Uninterrupted demand is equal to actual demand during the requested interruption minus

cond Third Revised Sheet No. 35 Canceling P.S.C. No. 35, First Second Revised Sheet No. 35 Rate H Wholesale Renewable Energy Program This Renewable Energy Program is a rider to Rates B, C, E and G. The purpose of this program is to provide EKPC owner-members with a source of renewable energy or renewable energy attributes for resale to their retail members.

1. "Renewable energy" is that electricity which is generated from renewable sources including but not
   limited to: solar, wind, hydroelectric, geothermal, landfill gas, biomass, biodiesel used to generate electricity, agricultural crops or waste, all animal and organic waste, all energy crops and other renewable certified resources.

2. A "Renewable Energy Certificate" ('REC') is the tradable renewable energy attribute which
   represents the commodity formed by unbundling the environmental-benefit attributes of a unit of renewable energy from the underlying electricity. One REC is equivalent to the environmental- benefits attributes of one MWh of renewable energy. Availability of Service Option A: Owner-members may participate in the program by contributing monthly as much as they like in $2.50 increments (e.g. $2.50, $5.00, $7.50, or more per month). Funds provided by owner-members are not refundable. Option B: Option B is a five-year pilot program. On and before March 25,2025, oOwner-members may, after entering into an agreement with their retail member and EKPC, offer renewable energy to offset a portion or all of the energy consumed by the retail member utilizing owner-member's firm service rates. Option C: Owner-member s may participate in this REC program, after entering into an agreement with their commercial and industrial ("C&l') retail member, by offering the C&l retail members the opportunity to purchase RECs through their owner-member and EKPC to offset up to all of their energy consumption with RECs, resulting in that portion of energy consumed to be considered renewable.

cond Third Revised Sheet No. 36 Canceling P.S.C. No. 35, First Second Revised Sheet No. 36 Eligibility All EKPC owner-members are eligible for this rider. Under Option A, the owner-member will indicate the amount of voluntary Renewable Energy Program Contributions that the owner-member intends to purchase monthly. All owner-members will have executed a Renewable Energy Program Agreement with the participating retail member. Under Option B, the retail member in conjunction with the owner-member and EKPC, will determine the amount of renewable energy to be provided to the retail member. The minimum renewable energy capacity to be purchased, supplied, or secured by EKPC in the agreement should be 1 MW. The maximum annual renewable energy under the agreement can't exceed the participating retail member's average annual consumption over the previous three (3) years. For new businesses with no usage history, the maximum annual renewable energy under the contract will be estimated. The type of renewable energy will be selected by individually participating retail members. Retail members having multiple services across the EKPC system may aggregate consumption and renewable energy totals into a single agreement. Under Option C, C&l retail members, in conjunction with the owner-memb er and EKPC, will determine the type of renewable resource and number amount of RECs the owner-member and EKPC will purchase monthly on behalf of the participating retail member. The original agreement will expire after one (1) year, but will automatically renew monthly until the retail member provides 60 days' notice of cancellation. The retail member may also amend the agreement to change the number amount of RECs or the type of renewable resource generating such RECs they will purchase. EKPC may sell and retire RECs generated by EKPC when applicable with a market-based rate per REC. The sum of renewable energy purchased under Option B and RECs purchased and retired under Option C shal l not exceed the customer's annual usage.

Option A Renewable Energy Program Contributions: The monthly Renewable Energy Program Contributions by the owner-member is the total monthly voluntary contribution by the owner-member's participating retail members in any $2.50 increments for the type of renewable energy resources (Landfill Gas, Solar, Wind, Hydroelectric) chosen by the participating retail member. EKPC will generate, purchase renewable energy, or purchase RECs equal to the monthly sum of Renewable Energy Program Contributions for each renewable energy resource type minus $0.25 per increment retained to help offset administrative and advertising costs. For Renewable Energy Program Contributions assigned by the retail member for renewable energy resources that EKPC does not own, EKPC will purchase the appropriate type of RECs equaling the total contribution amount and will retire the associated RECs. For Renewable Energy Program Contributions assigned by the retail member for renewable energy resources that EKPC owns and operates, EKPC will allocate the appropriate generation (kwhs) and costs to the assigned renewable energy program contribution and retire the associated RECs.

T/D T/D

cond Third Revised Sheet No. 37 Canceling P.S.C. No. 35, First Second Revised Sheet No. 37 Option C Participating C&l retail members will pay the market value of the RECs purchased on their behalf without markup from the owner-member or EKPC. They will have the option to instruct the owner-member and EKPC to purchase: (i) RECs covering a set percentage of their energy consumption each month; (ii) a set dollar amount of RECs per month; or (iii) a set number of MWhs. The participating C&l retail member can set a REC price that requires additional approvals for EKPC to purchase RECs per the Agreement. EKPC will act as the participating retail member's REC purchasing agent including settling the REC market transactions and REC retirements

Under Option A, EKPC will bill the owner-member at the rate of $2.50 per increment. The sum of the Renewable Energy Program Contributions from each renewable energy resource type pledged under this tariff shall constitute the total amount that the owner-member may be billed during a normal billing period. Existing Wholesale Renewable Energy Program ("Envirowatts") retail participants will be billed at the existing retail rate from their owner-member. Under Option B, EKPC will increase the owner-member monthly wholesale power bill by the negotiated and contracted renewable energy rate and delivered renewable energy for each participating agreement while providing a credit for the avoided cost of base fuel per MWh of renewable energy delivered and capacity credits when applicable. Under Option C, EKPC will increase the owner-membe r monthly wholesale bill for the RECs purchased at the market price plus a monthly transactional fee of $100 and incurred volumetric fees. Volumetric fees includes per REC costs paid directly to other parties by EKPC to procure specific types of RECs, (ie. Green- e Energy certified RECs) and per REC costs paid directly to other parties by EKPC to retire RECs via ® industry recognized renewable attribute registries. For any agreement instructing EKPC to purchase REC's in advance of the billing cycle, a monthly carrying charge equal to 1112 of the annual short-term borrowing rate will be added to the participant's bill. Terms of Service and Paym ent This rate shall be subject to all other terms of service and payment of the wholesale power tariff.

cond Third Revised Sheet No. 38 Canceling P.S.C. No. 35, First Second Revised Sheet No. 38 Fuel Adjustment Clause Under Options A and C, the fuel adjustment clause is not applicable to the Renewable Energy Program Contributions. Under Option B, EKPC will provide a credit on the owner-member's monthly wholesale power bill for the avoided cost of the base fuel and the Fuel Adjustment Clause equal to the delivered renewable energy monthly for each participating agreement. Environmental Surchar ge Under Options A and C, the environmental surcharge is not applicable to the Renewable Energy Program Contributions. Under Option B, EKPC will provide a credit on the owner-member's monthly wholesale power bill for the avoided cost of the variable environmental surcharge equal to the delivered renewable energy monthly for each participating agreement. Total Credits Under Option B, the total credit on the owner-member's monthly wholesale power bill will be the total of the avoided costs from base fuel, the fuel adjustment clause, capacity credits when applicable, and the variable environmental surcharge for the delivered renewable energy. The total credit will be limited to the lesser of the total credit as described in the Fuel Adjustment Clause and Environmental Surcharge sections above or the PJM Localized Marginal Cost ("LMP").

cond First Revised Sheet No. 47 Cancelling P.S.C. No. 35, First Revised Sheet No. 47 Rate SEM Symmetrical Earnings Mechanism This Symmetrical Earnings Mechanism is a rider to Rates B, C, DCP, E, and G, as well as applicable to all special contract customers. ln all territories of Owner-Member Cooperatives ("Owner-Member") of EKPC. Available to Owner-Memb ers and End-Use Retail Members ("Retail Member"), pursuant to Paragraph 6 of the Joint Stipulation, except for any End-Use Retail Member taking service under Rate DCP Attachment A, as of the date of the issuance of a credit or debit pursuant to Paragraph 4 of the Joint Stipulation, Settlement Agreement and Recommendation approved in Case No. 2025-00208. Purpose EKPC has committed to col lect or return any margins to its Owner-Members for contemporaneous collection or pass-through to Retail Members in the form of a bill charge or credit in the event that EKPC's achieves per-book margins in excess of a fall below a 1.40 TIER or are in excess of a 1.60 TIER in any calendar year. Any excess margins to be collected or returned will be allocated based upon the percentage of each EKPC rate class' total revenue for the most recent calendar year. EKPC will make an annual filing with the Commission setting forth its calculations of margins and any required bill charge or credit for the most recent calendar year on or before April 30 February 1st of the following year. Also included in the thannual filing will be a true-up of any difference between EKPC's audited and unaudited financials, over/under collections/refunds during the current year, and any other adjustments that are necessary to assure that the SEM is accurate and correct. Methodology Excess Margins. EK PC will determine any excess margins for the most recent calendar year by comparing the per book margins reflected in the achieved TIER with the margins needed to produce a 1.640 TIER. If the margins reflected in the achieved TIER exceed the margins needed to produce a 1.640 TIER, then the dollar difference in the margins will constitute excess margins to return to the Owner-Members and Retail Members. lf the margins needed to produce a 1.640 TIER exceeds the margins reflected in the achieved TIER, then there will be no excess margins returned for the calendar year.

P.S.C. No. 35, Second Revised Sheet No. 47.1 Cancelling P.S.C. No. 35, First Revised Sheet No. 47.1 PC will determine any deficient margins for the most recent calendar year by Deficient Margins. EK comparing the per book margins reflected in the achieved TIER with the margins needed to produce a 1.4 TIER. If the margins reflected in the achieved TIER are less than the margins needed to produce a 1.4 TIER, then the dollar difference in the margins will constitute deficient margins to collect from the Owner- Members and Retail Members. If the margins needed to produce a 1.4 TIER are less than the margins reflected in the achieved TIER, then there will be no deficient margins to collect for the calendar year. Minimum Excess/Deficient Margin. Any calculated Excess/Deficit Margin will be recorded annually as a regulatory liability/asset. EKPC will not refund/collect any Excess/Deficit Margin until the cumulative balance meets or exceeds $10 million. In the final year of operation under this tariff, any remaining Excess/Deficit Margin shall be refunded/collected regardless of amount. Large Special Contract Consideration If an Excess Margin is incurred Owen's Large Special Contract customer will receive the excess margin allocated to that class during the calendar year that the Excess Margin is passed from EKPC to the Owner- Member. Allocation of Excess or Deficient Marg ins. EKPC will determine its total revenues from its Owner-Members for the most recent calendar year in total and by applicable rate classes. For purposes of this calculation,

1. EKPC's rate classes are tariffed Rates B, C, E, and G and special contracts not based on tariffed
   rate schedules; and

2. EKPC's Rate E total revenues will include the solar panel production credits, green power billing,
   direct load control credits, and the generator credit; and

3. Any customer under EKPC's Rate Data Center Power (Rate DCP) will not be subject to any
   allocation of Excess or Deficient Margins if they are taking service under Attachment A of Rate DCP - Dedicated Resource Rider.

P.S.C. No. 35, Original Sheet No. 47.2 The allocation of the excess or deficient margin for the most recent calendar year will be performed using a two-step process. EKPC will first determine the percentage of total revenues each of its rate classes represent. The excess or deficient margin will be multiplied by this rate class percentage of total revenues to determine the allocation of the excess or deficient margin by rate class. If the rate class only has one retail member, then no further allocation will be necessary. For all other rate classes, EKPC will next determine the percentage of each rate class revenues provided by the Owner-Members. The allocated excess or deficient margin by rate class's will be multiplied by the applicable Owner-Member percentage for that rate class to determine the allocation of the excess or deficient margin by rate class by Owner- Member. EKPC will prepare and provide to each Owner-Member a schedule showing the allocation of the excess or deficient margin for the most recent calendar year by EKPC rate class by February 1st. The Owner-Member will utilize this schedule to determine the bill credit or debit that will pass-through the excess or deficient margins to their Retail Members in a manner consistent with the Stipulation approved by the Commission in Case No. 2025-00208. The Owner-Members will have flexibility in determining the manner to pass-through the excess or deficient margins to their Retail Members may also retain the excess margins to meet a debt covenant or hold off the filing of a rate case in the current year. Payment(s) o f Bill Credit or Collection of Deficient Margins. EKPC will include the applicable bill credit or debit to each Owner-Member on the billing invoices issued in a time period beginning no earlier than April usage billed in May and not to exceed twelve (12) months. in June of the year for the annual filing. However, in the event that it appear that the one time bill credit would create an adverse impact to EKPC's cash flows, EKPC may request and the Commission may order, other amortization periods on a case-by-case basis. Annual True-Ups. At the end of a calendar year, EKPC shall include in the following year's February 1 st filing the net of any amounts (positive or negative) equal to: (1) the difference between the prior year's per book margin and its final audited margin; (2) over/under collections from the current year; and (3) other adjustments that are necessary to assure that the amounts collected/refunded are correct and accurate. Commission Review. The mechanism described herein is the "rate" for purposes of Kentucky law and the annual calculation and schedule of amounts to be collected/refunded in accordance with this tariff shall not be considered a change in rates. Nevertheless, Commission shall review the operation and effect of the tariff every two-years. Such reviews shall assure that Rate SEM has been correctly calculated and that all amounts charged/refunded are correct. In the event of any errors, the Commission shall order a true-up to correct the miscalculation or misapplication. Nothing in this tariff shall be construed to limit in any way the Commission's authority under KRS 278.260 and KRS 278.270.

Exhibit C Proof of Revenues Attachment is an Excel spreadsheet being uploaded separately.

APPENDIX B

Revenue Increase Summary:

Description Proforma Interest on Long Term Debt 86,976,217$ 82,512,328$ 86,976,217$ 86,976,217$ TIER 1.50 1.50 1.50 1.50 Authorized Margins 43,488,109$ 41,256,164$ 43,488,109$ 43,488,109$ Proforma Net Margins (36,145,614)$ 27,981,809$ (20,106,096)$ (20,083,374)$ Required Increase in Revenues 79,633,723$ 13,274,355$ 63,594,205$ 63,571,483$ Assessment Rate 0.001554 0.001554 0.001554 0.001554 Additional Assessment due to Required Increase in Revenues 123,751$ 20,628$ 98,825$ 98,790$

Page 1 of 3

Commission EKPC AG/Nucor Joint Total Revenue Increase 79,757,474$ 13,294,983$ 63,693,031$ 63,670,273$ Percent Increase 7.51% 1.25% 6.00% 6.00%RecommendationApplicationSettlement Final

Increase Revenues to Account for Weather Normalization (34.33) - - Correct Normalization of Generation Maintenance Expense 9.89 - - Base Generation Maintenance Expense on 5-Yr Average (2.37) (2.37) (2.37) Generation Maintenance 6-year Amortization - (4.59) (4.59) Correct Error in Outage Insurance Revenue Proforma Adjustment (0.02) - - Remove Terminal Net Salvage - Thermal Generating Units (2.54) (2.56) (2.56) Remove Interim Retirements and Interim Net Salvage (6.26) - - Reduce Depreciation Expense to Reflect Extended Lifespans (14.20) - - Remove Deferred Prior Rate Case Amortization Expense (0.25) (0.25) (0.25) Reduce Amortization Expense for Deferred Smith 1 (8.59) (8.59) (8.59) 6 yr Amortization Adj for Expense for Deferred Smith 1 - (1.04) - 1 yr Amortization Adj for Expense for Deferred Smith 1 - - (0.38) Reduce Amortization Expense for Deferred 2019 Spurlock (0.43) - - Remove EEI, America's Power, NRECA, and Related Dues (0.66) - (0.66) Reduce Interest Expense Related to Higher Assignment to ES (6.71) - - RTEP Regulatory Asset 6-year Amortization - 3.37 3.34 Adjustment for Final Rate Case Expense - (0.03) (0.03) Appendix B

Page 2 of 3 Case No. 2025-00208

Original Commission AG/Nucor Joint Total Adjustments to EKPC's Requested Increase (66.46) (16.06) (16.09) Base Revenue Increase for EKPC 13.29$ 63.69$ 63.67$ AdjustmentsSettlementFinal ($ Millions)Base Revenue Increase Requested by EKPC 79.76$ 79.76$ 79.76$ Adjustments Summary:Adjustments to EKPC's Calculated Revenue Requirement:

Test Year Pro forma Pro forma Approved Approved Test Accounts Balances Adjustments Test Year Increase Year Balances Operating Revenues: Power Sales to Members 1,038,106,591$ (608,440,621)$ 429,665,970$ 63,670,273$ 493,336,243$ Power Sales Off System 49,049,722 (24,936,911) 24,112,811 24,112,811 Income Leased Property - Net 181,546 - 181,546 181,546 Other Operating Revenue 22,855,872 - 22,855,872 22,855,872 Total Operating Revenues 1,110,193,731$ (633,377,532)$ 476,816,199$ 63,670,273$ 540,486,472$ Expenses: Operation Expenses: Production Costs Excluding Fuel 88,914,227$ (60,953,375)$ 27,960,852$ 27,960,852$ Fuel Accounts 344,361,129 (327,966,613) 16,394,516 16,394,516 Other Power Supply 176,747,055 (128,566,665) 48,180,390 48,180,390 Transmission 56,019,189 3,159,479 59,178,668 59,178,668 Regional Market Expenses 6,057,712 - 6,057,712 6,057,712 Distribution 2,298,818 711,573 3,010,391 3,010,391 Customer Accounts - - - - Customer Service & Information 6,181,068 (133,182) 6,047,886 6,047,886 Sales 54,386 (21,874) 32,512 32,512 Administration & General 45,596,636 (2,643,159) 42,953,477 98,790 43,052,267 Total Operation Expenses 726,230,220$ (516,413,816)$ 209,816,404$ 98,790$ 209,915,194$ Maintenance Expenses: Production 111,326,948$ (582,080)$ 110,744,868$ 110,744,868$ Transmission 12,848,618 - 12,848,618 12,848,618 Distribution 2,720,381 - 2,720,381 2,720,381 General Plant 3,119,736 - 3,119,736 3,119,736 Total Maintenance Expenses 130,015,683$ (582,080)$ 129,433,603$ -$ 129,433,603$ Operating Expenses: Depreciation/Amortization 142,167,054$ (57,985,161)$ 84,181,893$ 84,181,893$ Taxes 248,465 - 248,465 248,465 Interest on Long Term Debt 107,001,951 (20,025,734) 86,976,217 86,976,217 Interest on Construction - - - - Other Interest Expense 358,803 - 358,803 358,803 Asset Retirement Obligations 1,576,871 (1,449,731) 127,140 127,140 Other Deductions 1,195,294 (808,691) 386,603 386,603 Total Operating Expenses 252,548,438$ (80,269,317)$ 172,279,121$ -$ 172,279,121$ Total Cost of Electric Service 1,108,794,341$ (597,265,213)$ 511,529,128$ 98,790$ 511,627,918$ Operating Margins 1,399,390$ (36,112,319)$ (34,712,929)$ 63,571,483$ 28,858,554$ Non-Operating Items: Interest Income 9,034,623$ 2,864,733$ 11,899,356$ 11,899,356$ Allowance for Funds Used during Construction - - - - Other Non-Operating Income 6,509,158 (4,691,458) 1,817,700 1,817,700 Other Capital Credits/Patronage Dividends 912,500 - 912,500 912,500 Total Non-Operating Items 16,456,281$ (1,826,725)$ 14,629,556$ -$ 14,629,556$ Net Patronage Capital & Margins 17,855,671$ (37,939,045)$ (20,083,374)$ 63,571,483$ 43,488,109$ Times Interest Earned Ratio (TIER) 1.17 0.77 1.50 Appendix B

Page 3 of 3 Case No. 2025-00208 Debt Service Coverage (DSC) Ratio 1.31 0.91 1.30

Authorized Increase 63,670,273$ Percent Increase 6.00% Authorized Pro forma Adjustments and Revenue Increase

APPENDIX C

The following rates and charges are prescribed for the customers in the area served by East Kentucky Power Cooperative, Inc. All other rates and charges not specifically mentioned herein shall remain the same as those in effect under the authority of this Commission prior to the effective date of this Order.

Page 1 of 2 Demand Charge per kW of Billing Demand in Excess of Demand Charge per kW of Contract Demand $8.95 Rate B Contract Demand Option 1: On-Peak Energy Charge per kWh Off-Peak Energy Charge per kWh Option 2: On-Peak Energy Charge per kWh Off-Peak Energy Charge per kWh Metering Point Charge $0.053765 $0.053688 $0.055908 $0.055354 $0.064644 $0.055641 $0.052531 $159.00 $11.92 $8.90 $9.23 $7.30 $9.17 Special Electric Contract Rate Rate C Rate E Rate G

Appendix C Page 2 of 2 Case No. 2025-00208 Substation Charge 1,000-2,999 kVa Substation Charge 3,000-7,499 kVa Substation Charge 7,500-14,999 kVa Substation Charge 15,000 kVa and over Annual Hours of Interruption: 200 Hours ($6.20) per kW 300 Hours ($6.90) per kW 400 Hours ($7.60) per kW 10-Minute Interruptible Credit90-Minute Interruptible CreditOn-Peak Energy Charge per kWhOff-Peak Energy Charge per kWhDemand Charge per MMBTu per month Energy Charge per MMBTu ($8.22) per kW ($6.20) per kW $0.056596 $0.052778 $1,165.00 $2,931.00 $3,526.00 $5,687.00 $655.45 $5.485 $9.40 Interruptible Service Rider Contract Steam Service Gallatin Steel Rate D

APPENDIX D

Page 1 of 4 Big Sandy Clark Farmers Grayson Jackson Nolin Owen Shelby Taylor Big Sandy Clark Farmers Grayson Jackson Nolin Owen Shelby $1,822,917 $1,425,723 $1,059,601 $249,048 $185,565 $369,290 $439,217 $900,223 $909,875 $528,745 $120,272 $341,239 $155,057 $643,990 $559,101 $205,257 $152,547 $194,897 $144,848 $387,973 $288,342 $458,788 $340,972 $940,293 $698,828 $894,490 $664,787 $558,850 $415,339 $201,783 $149,966 $196,993 $141,805 $244,688 $176,138 $689,790 $496,545 $216,777 $156,047 $447,256 $321,957 $41,223 $43,254 $32,146 $35,149 $63,112 $46,905 $80,425 $83,164 $61,808 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $1,127,685 $1,223,350 $909,197 $0 $0 $0 Total Proposed Approved Proposed Approved $6,898,140 $6,680,934 $4,965,286 Settled Settled Rate B Rate C

Page 2 of 4 Case No. 2025-00208 Taylor Big Sandy Clark Farmers Grayson Jackson Nolin Owen Shelby Taylor Big Sandy Clark Farmers Grayson Jackson Nolin Owen Shelby $1,189,503 $6,432,155 $4,563,140 $4,018,758 $2,545,159 $1,796,908 $1,582,537 $2,458,609 $1,748,730 $1,540,107 $2,676,785 $1,851,772 $1,630,856 $2,510,226 $1,785,514 $1,572,503 $1,639,058 $2,505,537 $1,776,272 $1,564,363 $4,845,085 $3,445,998 $3,034,891 $1,401,874 $3,527,671 $2,509,049 $2,209,720 $6,716,214 $4,908,079 $4,322,546 $6,516,117 $4,634,824 $4,081,891 $1,965,715 $1,398,178 $1,231,376 $6,624,234 $4,711,199 $4,149,154 $2,660,867 $1,843,059 $1,623,182 $1,672,976 $1,465,763 $1,742,157 $1,233,869 $1,081,190 $1,282,711 $567,624 $640,575 $528,852 $192,874 $757,859 $607,995 $437,665 $846,049 $745,116 $893,486 $786,897 $997,226 $878,257 $373,617 $437,278 $199,524 $229,071 $132,574 $438,982 $522,908 $78,580 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Total $56,671,743 $39,709,483 $34,972,155 Proposed Approved Proposed Approved $2,723,402 $2,403,499 $1,730,157 Settled Settled Rate G Rate E

Page 3 of 4 Case No. 2025-00208 Taylor Big Sandy Clark Farmers Grayson Jackson Nolin Owen Shelby Taylor Big Sandy Clark Farmers Grayson Jackson Nolin Owen Shelby $1,344,423 $1,856,040 $348,497 $348,497 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total Total Proposed Approved Proposed Approved $5,027,007 $3,637,656 $4,346,698 $1,344,423 Settled Settled $348,497 $348,497

Page 4 of 4 Case No. 2025-00208 Taylor Big Sandy Clark Farmers Grayson Jackson Nolin Owen Shelby Taylor $17,602,469 $14,610,162 $1,230,726 $2,580,308 $1,860,020 $1,629,442 $3,328,700 $2,145,247 $1,910,983 $2,831,842 $2,096,460 $1,806,994 $5,424,736 $5,490,747 $4,312,249 $1,824,623 $1,305,160 $1,087,791 $4,108,696 $3,245,435 $3,135,416 $5,843,403 $4,352,042 $3,697,820 $1,594,860 $1,075,806 $1,010,831 $4,365,954 $3,031,195 $2,794,435 $8,189,842 $7,416,340 $5,575,117 $4,780,719 $2,875,589 $2,292,668 $1,896,163 $7,720,604 $5,878,044 $5,002,157 $2,781,139 $2,044,842 $1,773,148 $889,303 $777,262 $0 $0 $0 $0 $0 $0 $8,200,415 $6,160,107 $5,365,233 Total Total $79,731,915 $55,632,035 $55,590,808 Proposed Approved $1,856,040 Settled Total

Service List for 2025-00208

• Allyson Honaker Honaker Law Office, PLLC 1795 Alysheba Way Suite 1203 Lexington, KY 40509
• Angela M Goad Assistant Attorney General Office of the Attorney General Office of Rate Intervention 700 Capitol Avenue Suite 20 Frankfort, KY 40601-8204

• Greg Cecil
  4775 Lexington Road P. O. Box 707 Winchester, KY 40392-0707

• Heather Temple Honaker Law Office, PLLC 1795 Alysheba Way
  Suite 1203 Lexington, KY 40509

• Jacob Watson
  4775 Lexington Road P. O. Box 707 Winchester, KY 40392-0707

• Jody Kyler Cohn Boehm, Kurtz & Lowry 425 Walnut Street Suite 2400 Cincinnati, OH 45202

• John G Horne, II Office of the Attorney General Office of Rate Intervention 700 Capitol Avenue Suite 20 Frankfort, KY 40601-8204

• Denotes served by Email

• Lawrence W Cook Assistant Attorney General Office of the Attorney General Office of Rate Intervention 700 Capitol Avenue Suite 20 Frankfort, KY 40601-8204

• Meredith L. Cave Honaker Law Office, PLLC 1795 Alysheba Way Suite 1203 Lexington, KY 40509

• Michael West Office of the Attorney General Office of Rate Intervention 700 Capitol Avenue Suite 20
  Frankfort, KY 40601-8204

• Honorable Michael L Kurtz Attorney at Law Boehm, Kurtz & Lowry 425 Walnut Street Suite 2400 Cincinnati, OH 45202

• East Kentucky Power Cooperative, Inc. 4775 Lexington Road P. O. Box 707 Winchester, KY 40392-0707

• Toland Lacy Office of the Attorney General 700 Capital Avenue Frankfort, KY 40601

• Denotes served by Email Service List for Case 2025-00208