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MEMORANDUM

PRIVILEGED AND CONFIDENTIAL — ATTORNEY-CLIENT COMMUNICATION

To: Marcus Petrov, Vice President, Tax, Dunmore Energy Holdings Ltd. Fiona Kessler, Chief Financial Officer, Dunmore Energy Holdings Ltd.

From: Sylvia Hartwell, Partner, Calderwood & Harkness LLP Robert Jansen, Associate, Calderwood & Harkness LLP

Date: March 24, 2026

Re: Structuring Memorandum — IRC § 6418 Transferable Credit Monetization for the Ridgeway Wind Project

Matter No.: 1016-00008

Billing Code: 09417.00001

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I. Executive Summary

The purpose of this memorandum is to set forth Calderwood & Harkness LLP's ("C&H") preliminary analysis of the proposed structure for monetizing Production Tax Credits ("PTCs") generated by the 250 MW Ridgeway Wind Project (the "Project") through a direct transfer election under Section 6418 of the Internal Revenue Code of 1986, as amended ("IRC" or the "Code"), as enacted by the Inflation Reduction Act of 2022 (Pub. L. No. 117-169) (the "IRA"). This memorandum identifies the key structural, legal, and tax considerations that DEH and its advisors should evaluate in connection with the proposed transaction.

Our client in this engagement is Dunmore Energy Holdings Ltd. ("DEH"), a Cayman Islands exempted limited company (registry number CR-284319), headquartered at 4th Floor, Harbour Place, 103 South Church Street, George Town, Grand Cayman KY1-1002, Cayman Islands. DEH is the ultimate parent entity of the project company.

The proposed transferor entity is Ridgeway Wind Energy LLC ("RWE"), a Delaware limited liability company (file number 7603517), which is wholly owned by Dunmore Renewables Inc. ("DRI"), a Delaware corporation (file number 7491826). DRI is in turn a wholly owned U.S. operating subsidiary of DEH. Because RWE is a single-member LLC that has not elected to be classified as a corporation for federal income tax purposes, RWE is a disregarded entity for U.S. federal income tax purposes. Accordingly, DRI is the regarded taxpayer that would claim PTCs generated by the Project and make the transfer election under IRC § 6418. As discussed in greater detail in Section III.A below, the analysis of whether the election is properly made by DRI or by RWE, given the disregarded entity status, is a threshold question that must be resolved before definitive documentation is prepared.

The prospective transferee is Pinnacle Atlantic Partners LP ("Pinnacle" or "PAP"), a Delaware limited partnership (file number 7255043), headquartered at 277 Park Row, 18th Floor, New York, NY 10172. Pinnacle is a large, diversified financial services firm with substantial federal income tax liability and significant experience in clean energy tax credit purchase transactions.

The primary rationale for pursuing a transfer under IRC § 6418 rather than direct utilization of the PTCs by DRI is that DEH has limited federal income tax liability due to legacy intangible drilling cost ("IDC") deductions and prior net operating losses ("NOLs"). These tax attributes substantially reduce the consolidated group's current federal income tax liability, rendering direct utilization of PTCs economically inefficient. A transfer under IRC § 6418 allows DEH and its subsidiaries to monetize the PTCs for cash consideration without entering into a traditional tax equity partnership flip structure, which would require the formation of a partnership, the admission of a tax equity investor, and the negotiation of complex partnership allocation provisions. The § 6418 transfer mechanism is considerably simpler from a structural perspective, preserves DRI's sole ownership of the Project through RWE, and avoids the governance and control complications inherent in tax equity transactions.

Based on the energy production estimate prepared by Meridian Technical Advisors LLC ("Meridian"), using a P50 net capacity factor of 38.2%, the estimated annual PTC for Year 1 (TY2025) is approximately $25,295,655. Over the 10-year PTC eligibility period (TY2025 through TY2034), the estimated aggregate PTC value is approximately $253,000,000 (nominal, pre-inflation adjustment). At the proposed transfer price of $0.92 per $1.00 of credit, the estimated 10-year aggregate transfer consideration payable by Pinnacle to DRI/RWE is approximately $232,760,000.

This engagement is currently in the prospective scoping phase. No definitive transaction documents have been negotiated or circulated. Pinnacle has delivered a non-binding indicative term sheet, which C&H has reviewed at a high level and will address in a separate commentary memorandum. This memorandum is intended to identify and analyze the key structural, legal, and tax considerations for the proposed transaction, and to recommend next steps for the client's evaluation.

The governing law for the proposed Transfer Agreement is expected to be New York. C&H is coordinating with Grayson Birch & Co. LLP ("Grayson Birch"), DEH's independent tax advisor, on PTC eligibility analysis, cost segregation, and IRS pre-filing registration matters. Howard Ellison is the lead partner at Grayson Birch responsible for these workstreams. In addition, Meridian Technical Advisors LLC (Dr. Paul Marlowe, PE, lead engineer) has prepared the energy production estimate and the commercial operations date ("COD") certification for the Project.

II. Background and Project Overview

A. Dunmore Energy Holdings Ltd. — Corporate Overview

DEH is a privately held energy company controlled by the Dunmore family. Callum Dunmore serves as Chairman of the board of directors and holds a 68% equity interest in DEH. The remaining equity interests are held by other members of the Dunmore family and certain long-tenured senior executives, the details of which are not material to this memorandum.

DEH's principal operations include upstream oil and gas exploration and production activities in the Permian Basin (spanning portions of West Texas and southeastern New Mexico), as well as a growing portfolio of renewable energy projects across the western United States. The renewable energy portfolio currently includes the Ridgeway Wind Project (the subject of this memorandum), two solar photovoltaic projects in development in Nevada and Arizona, and an early-stage battery energy storage project in Oregon. The transition toward renewable energy reflects both a strategic diversification initiative and a response to the favorable economics made available by the IRA's enhanced tax credit regime.

For the fiscal year ended December 31, 2025, DEH's consolidated revenue was approximately $1.34 billion. Notwithstanding this substantial revenue base, DEH's consolidated federal income tax liability has been significantly offset by legacy IDC deductions attributable to its upstream oil and gas operations, as well as NOLs carried forward from prior taxable years. This limited federal income tax liability is the primary driver for pursuing a § 6418 transfer of the Project's PTCs rather than direct credit utilization by DRI. Direct utilization would require sufficient federal income tax liability against which to apply the PTCs, and the current projections prepared by Grayson Birch indicate that DRI's share of federal income tax liability will be insufficient to fully absorb the annual PTC over the 10-year eligibility period. A transfer under § 6418 converts the credits to cash without requiring tax capacity at the transferor level.

B. Entity Structure

The relevant entity chain for the proposed transaction is as follows:

Dunmore Energy Holdings Ltd. (Cayman Islands exempted company, registry number CR-284319)

↓ 100% ownership

Dunmore Renewables Inc. (Delaware corporation, file number 7491826; principal office at 900 Bridger Boulevard, Suite 410, Billings, MT 59101)

↓ 100% sole member

Ridgeway Wind Energy LLC (Delaware limited liability company, file number 7603517; project company)

RWE is the sole owner and operator of the Ridgeway Wind Project and is the entity that generates and is entitled to the PTCs under IRC § 45. As noted above, RWE is a disregarded entity for U.S. federal income tax purposes because it is a single-member LLC that has not elected to be treated as a corporation under the "check-the-box" regulations (Treas. Reg. § 301.7701-3). Its sole member is DRI, a Delaware C corporation. Accordingly, for federal income tax purposes, all items of income, deduction, and credit generated by RWE are treated as items of DRI.

DRI is the taxpayer that would claim the PTCs on its federal income tax return and would make the transfer election under IRC § 6418. The analysis below addresses the interaction between the disregarded entity rules and the § 6418 election mechanics, including the IRS pre-filing registration requirements that require identification of both the regarded taxpayer (DRI) and the underlying eligible entity (RWE) that owns the qualified facility.

C. Ridgeway Wind Project

The following summarizes the key technical and commercial parameters of the Project:

Project Name: Ridgeway Wind Project

Location: The Project is situated on approximately 28,000 acres of leased ranchland located approximately 14 miles northeast of Miles City, in Custer County, Montana. The leasehold interests are held by RWE pursuant to a series of land lease agreements with five private landowners. The leases have initial terms of 40 years with renewal options, and are recorded with the Custer County Clerk and Recorder's Office.

Nameplate Capacity: 250 MW. The Project consists of 83 wind turbine generators, each with a rated capacity of 3.0 MW, totaling 249 MW, plus one additional 1.0 MW unit that serves as a substation backup generator. The turbines are General Electric Vernova 3.0-148 units with a rotor diameter of 148 meters and hub height of 105 meters.

Net Capacity Factor (P50): 38.2%, as determined by the energy production estimate prepared by Meridian Technical Advisors LLC, dated September 12, 2025 (the "Energy Production Estimate"). The P50 estimate represents the median expected annual energy production — that is, there is a 50% probability that actual production will equal or exceed this level. For purposes of financing and credit transfer structuring, the P50 figure is the standard benchmark used in the industry.

Construction Start Date: April 6, 2023. Construction commenced with the mobilization of earthwork equipment and the beginning of access road construction. This date is relevant to the determination of the beginning of construction under the IRA's transition rules for PTC-eligible facilities.

Commercial Operations Date (COD): November 14, 2025, as certified by Meridian in the COD Certification dated November 18, 2025. The COD Certification confirms that all 83 turbines (plus the backup unit) were mechanically complete, electrically interconnected to the grid, and capable of sustained commercial power generation as of November 14, 2025. For purposes of IRC § 45, the COD establishes the placed-in-service date of the facility and marks the beginning of the 10-year PTC eligibility period.

Total Project Cost: $412,000,000. This figure includes all hard costs (turbine procurement, balance of plant construction, electrical infrastructure, and interconnection facilities), soft costs (development fees, legal and advisory fees, permitting costs, and land lease prepayments), and capitalized interest during construction.

Financing:

• Debt: $288,400,000 construction-to-term loan facility provided by Redstone Capital Bank, N.A. (OCC Charter No. 18742), representing a 70% loan-to-cost ratio ($412,000,000 × 0.70 = $288,400,000). The loan was originated as a construction facility and converted to a term loan upon achievement of COD in accordance with the terms of the Credit Agreement. The term loan has a maturity of 15 years from COD, a fixed interest rate of 5.875% per annum, and is secured by a first-priority lien on substantially all assets of RWE, including the turbines, leasehold interests, the PPA, and all project accounts.

• Equity: $123,600,000 contributed by DRI, representing a 30% loan-to-cost ratio ($412,000,000 × 0.30 = $123,600,000). The equity was contributed in the form of cash capital contributions from DRI to RWE in installments corresponding to construction milestones.

Outstanding Loan Principal as of March 1, 2026: $271,600,000. Principal amortization of $16,800,000 has occurred since the loan's conversion to a term facility, reflecting scheduled amortization payments made in December 2025 and March 2026.

Credit Agreement and Depositary Agreement: Both dated March 28, 2023, between RWE (as borrower) and Redstone Capital Bank, N.A. (as administrative agent and lender), governed by New York law. The Credit Agreement contains customary project finance covenants, including a prohibition on transfers of tax attributes without prior lender consent (Section 7.14, discussed in detail in Section VIII below). The Depositary Agreement establishes the revenue account waterfall governing the application of project revenues, including debt service, reserve funding, and distribution provisions.

Power Purchase Agreement: RWE has entered into a 20-year fixed-price power purchase agreement with Great Plains Municipal Power Authority ("GPMPA") at a price of $38.50 per MWh. The PPA was executed on June 12, 2023. The contract term commences on the COD (November 14, 2025) and runs through November 13, 2045. GPMPA is a municipal power authority organized under Montana law that serves as the wholesale power supplier for approximately 14 member municipalities in central and eastern Montana. The PPA provides for the sale of all net energy output from the Project, with curtailment provisions and liquidated damages for failure to deliver minimum annual energy quantities.

Interconnection: The Project holds MISO Queue Position J-1147 and has executed a Generator Interconnection Agreement ("GIA") with NorthStar Transmission Holdings LLC, a Delaware limited liability company that owns and operates the transmission infrastructure in the relevant portion of the MISO transmission system. The GIA was executed on September 3, 2024, and provides for the interconnection of the Project at the Miles City 230 kV substation. The Project achieved full unrestricted interconnection service as of the COD.

III. Eligibility Analysis — IRC § 6418 Transfer Election

A. Eligible Taxpayer Status of the Transferor

Under IRC § 6418(a), as enacted by Section 13801 of the IRA, an "eligible taxpayer" that determines any "specified credit portion" for a taxable year may elect to transfer all or a portion of such credit to an unrelated transferee taxpayer for cash consideration. The election permits the transferor to monetize the credit without entering into a partnership structure with a tax equity investor, and without the transferor itself having sufficient federal income tax liability to utilize the credit.

The term "eligible taxpayer" is defined in IRC § 6418(f)(2) as any taxpayer other than (i) a tax-exempt entity described in IRC § 168(h)(2), or (ii) a governmental entity (i.e., any state or political subdivision thereof, the United States, any agency or instrumentality of the foregoing, or any Indian tribal government). DRI is a Delaware C corporation that is not tax-exempt and is not a governmental entity. Accordingly, DRI satisfies the definition of an "eligible taxpayer" for purposes of IRC § 6418.

The analysis of the transferor's eligible taxpayer status is complicated by the disregarded entity treatment of RWE. RWE is the entity that owns the qualified facility and generates the electricity from which PTCs arise. However, because RWE is disregarded for federal income tax purposes, all items of income, deduction, and credit attributable to RWE are treated as items of DRI, its sole member. Under Treasury Regulations Section 1.6418-2(a)(1), the transfer election under § 6418 is made by the taxpayer that would otherwise be entitled to claim the credit on its federal income tax return — in this case, DRI. The regulations further provide, however, that the pre-filing registration (discussed in Section VI) must identify both the regarded taxpayer (DRI) and the underlying "applicable entity" that owns the eligible property or qualified facility generating the credit. In this context, RWE is the applicable entity.

We note that the IRS issued final regulations under § 6418 on March 11, 2024 (T.D. 9993, 89 Fed. Reg. 17,548), which clarified the treatment of disregarded entities in the transfer election context. Under Treas. Reg. § 1.6418-2(a)(2), a disregarded entity is not treated as an "eligible taxpayer" for purposes of making the election; the election must be made by the regarded owner. However, the disregarded entity remains the "applicable entity" for purposes of identifying the facility and completing the pre-filing registration. This two-level identification requirement — regarded taxpayer as the electing party, disregarded entity as the facility owner — is consistent with the IRS's approach to the pre-filing registration portal and ensures that the IRS can match the credit to the specific facility generating the electricity.

Conclusion: DRI is the eligible taxpayer for purposes of the IRC § 6418 transfer election. RWE is the applicable entity that owns the qualified facility and generates the PTCs. The transfer election will be made by DRI on its timely filed federal income tax return for each taxable year in which PTCs are generated and transferred.

B. Specified Credit — Production Tax Credit Under IRC § 45

The PTC under IRC § 45 is a "specified credit portion" eligible for transfer under IRC § 6418(f)(1)(A). The IRA expanded the list of credits eligible for transfer under § 6418, and the PTC under § 45 is expressly included.

The Ridgeway Wind Project is a "qualified facility" under IRC § 45(d)(1), which defines a qualified facility for wind energy as any facility that uses wind to produce electricity and for which construction begins before January 1, 2025. Construction of the Ridgeway Wind Project commenced on April 6, 2023, which is after December 31, 2021 (the effective date of the IRA's enhanced PTC provisions) and before January 1, 2025. The facility was placed in service on November 14, 2025 (prior to January 1, 2026), satisfying the placed-in-service requirement for PTC eligibility.

Under the IRA's transition rules, a taxpayer may elect to claim either the PTC under § 45 or the Investment Tax Credit ("ITC") under § 48 for a qualified facility. DEH and Grayson Birch have performed a comparative analysis and determined that the PTC election is more favorable for the Ridgeway Wind Project given the Project's high capacity factor (38.2% P50) and the 10-year credit period. At a capacity factor of 38.2%, the present value of PTCs over the 10-year period exceeds the one-time ITC that would be available under § 48 based on the Project's eligible basis. This determination is consistent with industry practice for wind projects with capacity factors above approximately 30%, where the PTC generally provides greater economic value than the ITC.

We note that, under the IRA, new clean energy facilities placed in service after December 31, 2024 may alternatively be eligible for the technology-neutral clean electricity PTC under IRC § 45Y or the clean electricity ITC under § 48E. However, because the Ridgeway Wind Project commenced construction before January 1, 2025, and is a wind facility that qualifies under the legacy § 45 provisions, DEH and Grayson Birch have elected to claim PTCs under § 45 rather than § 45Y. This election is irrevocable once made for the first taxable year in which the credit is claimed.

C. Transferee Eligibility — Pinnacle Atlantic Partners LP

Under IRC § 6418(a), the transferee must be a taxpayer that is not related to the eligible taxpayer within the meaning of IRC § 267(b) or § 707(b)(1). These provisions define "related persons" broadly to include members of a family, entities under common control, and partnerships in which the same persons own more than 50% of the capital or profits interests.

Pinnacle Atlantic Partners LP is a Delaware limited partnership with no ownership, familial, or other relationship to DEH, DRI, RWE, or any member of the Dunmore family. C&H has conducted a preliminary review of the ownership structures of both DEH and Pinnacle and has identified no overlapping officers, directors, equity holders, or beneficial owners. Pinnacle's general partner is Pinnacle Atlantic GP Inc., a Delaware corporation, and its limited partners consist of various institutional investors, pension funds, and high-net-worth individuals, none of whom, to our knowledge, have any affiliation with the Dunmore family or DEH's affiliated entities. We recommend that both parties exchange officer, director, and beneficial owner lists and execute representations confirming the absence of any relationship described in IRC § 267(b) or § 707(b)(1) as a condition to closing.

Pinnacle has an average annual federal income tax liability of approximately $480,000,000 over the past three fiscal years (FY2023, FY2024, and FY2025), which is more than sufficient to absorb the estimated annual PTC of approximately $25.3 million. The ratio of Pinnacle's annual tax liability to the annual PTC is approximately 19:1, providing substantial headroom and eliminating any concern that Pinnacle might be unable to utilize the transferred credits in the year of transfer. Under IRC § 6418(d)(1), the transferred credit may not reduce the transferee's tax liability below zero — that is, the credit is non-refundable in the hands of the transferee. Given Pinnacle's substantial tax liability, this limitation is not expected to be a constraint.

Pinnacle has previously closed approximately $1.2 billion in IRC § 6418 credit purchases across solar, wind, and battery storage projects since the IRA's enactment, demonstrating institutional familiarity with the transfer mechanics, IRS registration requirements, and market documentation standards. This prior experience should facilitate an efficient negotiation and documentation process.

Pinnacle is represented by Hargrove, Liddell & Strauss LLP ("HL&S"), located at 400 Lexington Avenue, Suite 3200, New York, NY 10170. The lead contacts at HL&S are Nathaniel Strauss (partner, Tax) and Catherine Yoon (senior associate, Tax). C&H has previously transacted with HL&S on unrelated matters and anticipates a constructive working relationship on the documentation for this transaction.

IV. PTC Computation

A. Base Credit Rate

The base credit rate for the PTC under IRC § 45(a)(1) is $0.0055 per kilowatt-hour ("kWh") of electricity produced from a qualified energy resource at a qualified facility during the 10-year period beginning on the date the facility is placed in service. This rate reflects the inflation-adjusted base rate applicable to wind facilities placed in service in calendar year 2025, as published in IRS Notice 2025-XX (pending final publication) pursuant to the inflation adjustment mechanism set forth in IRC § 45(e)(2). The base rate is adjusted annually for inflation and rounded to the nearest 0.1 cent.

It is important to note that this base rate reflects the "non-enhanced" credit amount — that is, the credit rate available to facilities that do not satisfy the prevailing wage and apprenticeship requirements of IRC §§ 45(b)(7) and 45(b)(8). As discussed immediately below, the Ridgeway Wind Project has satisfied these requirements, entitling it to a 5x bonus multiplier that significantly increases the effective credit rate.

B. Bonus Credit Multiplier — Prevailing Wage and Apprenticeship Requirements

Under IRC § 45(b)(6)(B), the base credit rate is multiplied by five (5) if the qualified facility satisfies the prevailing wage and apprenticeship requirements set forth in IRC §§ 45(b)(7) and 45(b)(8), respectively. These requirements are as follows:

Prevailing Wage Requirement (IRC § 45(b)(7)): Any laborers and mechanics employed by the taxpayer or any contractor or subcontractor in the construction, alteration, or repair of the qualified facility must be paid wages at rates not less than the prevailing rates for construction, alteration, or repair of a similar character in the locality in which the facility is located, as determined by the Secretary of Labor in accordance with subchapter IV of chapter 31 of title 40, United States Code (the Davis-Bacon Act). This requirement applies both during construction and for any alteration or repair of the facility during the entire PTC eligibility period.

Apprenticeship Requirement (IRC § 45(b)(8)): The taxpayer must ensure that, with respect to the construction of the qualified facility, not less than the applicable percentage of total labor hours are performed by qualified apprentices. For facilities for which construction begins in 2023, the applicable percentage is 12.5%. Additionally, the taxpayer must comply with the ratio requirements (the ratio of apprentices to journeyworkers) established by the applicable registered apprenticeship program.

The Ridgeway Wind Project satisfied both the prevailing wage and apprenticeship requirements during the construction phase (April 6, 2023 through November 14, 2025). RWE's construction manager, Westland Infrastructure Group LLC, maintained certified payroll records demonstrating compliance with Davis-Bacon Act wage rates throughout the construction period, and the apprenticeship participation rate exceeded the 12.5% threshold. Grayson Birch & Co. LLP is currently preparing a detailed compliance memorandum confirming satisfaction of these requirements based on its review of the certified payroll records, apprenticeship certifications, and related documentation. C&H expects to receive a draft of this memorandum by approximately May 1, 2026.

It is critically important to note that the prevailing wage requirement extends beyond the construction phase and applies to any alteration or repair of the facility for the duration of the PTC eligibility period (TY2025 through TY2034). Failure to satisfy the prevailing wage requirement for any alteration or repair during this period could result in the loss of the 5x bonus multiplier for the applicable taxable year, thereby reducing the effective credit rate from $0.0275/kWh to $0.0055/kWh. The Transfer Agreement should include robust representations and covenants by DRI/RWE regarding ongoing prevailing wage compliance, and the indemnification provisions should address the transferee's exposure in the event of a failure to comply. This is a key risk factor that Pinnacle will likely focus on during negotiations.

Applying the 5x multiplier, the adjusted base credit rate is:

$0.0055 × 5 = $0.0275 per kWh

C. Energy Community Bonus Credit

Under IRC § 45(b)(11)(B), an additional 10% bonus credit applies if the qualified facility is located in an "energy community" as defined in IRC § 45(b)(11)(C). The energy community bonus is an additive enhancement to the credit — it increases the credit rate by 10% of the otherwise-applicable rate.

IRC § 45(b)(11)(C) defines "energy community" to include three categories of geographic areas:

(i) Brownfield sites as defined under certain provisions of the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA");

(ii) Metropolitan statistical areas or non-metropolitan statistical areas that have (or had at any time after December 31, 2009) 0.17% or greater direct employment or 25% or greater local tax revenues related to the extraction, processing, transport, or storage of coal, oil, or natural gas, and that have an unemployment rate at or above the national average; and

(iii) Census tracts (or directly adjoining census tracts) in which a coal mine has closed after December 31, 1999, or in which a coal-fired electric generating unit has been retired after December 31, 2009.

Custer County, Montana, where the Ridgeway Wind Project is located, qualifies as an energy community under the second category — IRC § 45(b)(11)(C)(iii) — based on historical fossil fuel employment levels in the county's statistical area. Custer County has a history of oil and gas extraction activity, and the relevant metropolitan or non-metropolitan statistical area has met the 0.17% direct employment threshold and the unemployment rate criterion in the most recently published IRS/Treasury guidance. The IRS published an updated list of qualifying energy communities in Notice 2024-30, which included the statistical area encompassing Custer County, Montana.

Applying the 10% energy community bonus, the effective credit rate is:

$0.0275 × 1.10 = $0.03025 per kWh

Important caveat: The energy community designation is subject to annual redetermination by the Treasury Department and the IRS. The unemployment rate component of the energy community test is based on data published by the Bureau of Labor Statistics, and changes in local employment conditions could cause Custer County's statistical area to lose its energy community qualification in a future taxable year. If the energy community bonus is lost for a particular taxable year, the effective credit rate for that year would revert to $0.0275/kWh (retaining the 5x prevailing wage/apprenticeship multiplier but losing the 10% energy community adder). This would reduce the annual PTC by approximately $2.3 million per year (approximately 10% of the full-rate PTC). Grayson Birch is monitoring the status of Custer County's qualification on an ongoing basis and will advise promptly if there is any indication that the designation may be at risk. The Transfer Agreement should allocate the risk of loss of energy community status between the parties — in most market transactions, the transferee bears the risk of future-year loss of energy community status (since it is outside the transferor's control), but the transferor indemnifies for any misrepresentation regarding the status as of the date of the Transfer Agreement.

D. Annual PTC Calculation

Based on the foregoing credit rate analysis and the energy production estimate prepared by Meridian, the estimated annual PTC for Year 1 (TY2025) is calculated as follows:

Nameplate capacity: 250 MW

Annual hours: 8,760 hours (non-leap year)

P50 net capacity factor: 38.2%

Estimated annual electricity generation: 250 MW × 8,760 hours × 0.382 = 836,220 MWh = 836,220,000 kWh

Effective PTC rate: $0.03025 per kWh

Estimated annual PTC (Year 1, TY2025): 836,220,000 kWh × $0.03025/kWh = $25,295,655

We note that an earlier estimate of approximately $34.65 million per year was reflected in certain preliminary marketing materials that were prepared by DRI's business development team using a higher capacity factor assumption (approximately 52%). That earlier estimate was based on a pre-construction resource assessment and did not incorporate the site-specific adjustments, turbine performance curves, and wake loss factors that are reflected in Meridian's final Energy Production Estimate. The P50-based figure of approximately $25.3 million per year is the canonical calculation for purposes of this structuring analysis and for the pricing discussions with Pinnacle. All references to PTC amounts in this memorandum and in subsequent transaction documents should use the Meridian P50-based estimate as the baseline.

E. 10-Year PTC Eligibility Period

Under IRC § 45(a)(2)(A)(ii), PTCs are available for electricity produced and sold by the taxpayer during the 10-year period beginning on the date the qualified facility is placed in service. For the Ridgeway Wind Project, this period runs from the placed-in-service date of November 14, 2025 through November 13, 2035, covering taxable years 2025 through 2034 for DRI (assuming DRI uses a calendar year as its taxable year, which we understand to be the case).

The estimated 10-year aggregate PTC, calculated on a nominal basis and without adjustment for annual inflation, is:

$25,295,655 × 10 ≈ $253,000,000 (rounded)

This figure is subject to annual inflation adjustments under IRC § 45(e)(2), which may increase or decrease the credit rate in each subsequent taxable year relative to the base year. The inflation adjustment is based on the GDP implicit price deflator published by the Bureau of Economic Analysis and is applied to the base credit rate before application of the 5x multiplier and the energy community bonus. In an inflationary environment, the actual 10-year aggregate PTC could exceed $253 million; in a deflationary or low-inflation environment, it could be lower. For purposes of the transfer pricing analysis in Section V, we use the nominal, unadjusted figure of $253 million as the baseline.

Additionally, the actual annual PTC will vary based on actual electricity generation, which will differ from the P50 estimate in any given year due to wind resource variability, turbine availability, curtailment events, and other operational factors. The annual true-up mechanism described in Section V.C is designed to address this variability.

V. Proposed Transfer Structure and Economics

A. Transfer Mechanism

The proposed transaction will be structured as a direct transfer election under IRC § 6418(a). DRI, as the regarded taxpayer and the eligible taxpayer for purposes of the transfer election, will elect to transfer the specified credit portion — i.e., the PTCs generated by the Ridgeway Wind Project — to Pinnacle for cash consideration.

The transfer mechanism under § 6418 is conceptually straightforward. For each taxable year in which the Ridgeway Wind Project generates PTCs, DRI will make an election on its timely filed (including extensions) federal income tax return to transfer all (or a portion, if applicable) of the PTCs to Pinnacle. Upon the making of this election and receipt of a valid IRS registration number, the credit is treated as if the transferee taxpayer (Pinnacle) were allowed the credit directly for the taxable year in which the credit was determined with respect to the transferor. The election is irrevocable for the taxable year in which it is made.

Critically, the transfer under § 6418 is not treated as a sale or exchange for federal income tax purposes. IRC § 6418(b)(4) provides that the transfer of a specified credit portion shall not be treated as a sale or other disposition of property. This has important consequences for both parties, as discussed in Section IX below.

The transfer of credits under § 6418 is fundamentally different from a traditional tax equity partnership flip structure. In a partnership flip, a tax equity investor acquires a partnership interest in the project company and is allocated tax credits and depreciation deductions through the partnership tax allocation provisions. The partnership flip structure involves complex partnership agreement negotiations, issues of economic substance, capital account maintenance, qualified income offset provisions, deficit restoration obligations, and the various safe harbors established by IRS guidance (including Revenue Procedure 2007-65 for wind projects). The § 6418 transfer, by contrast, is a simple two-party transaction in which credits are transferred for cash, with no equity investment, no partnership formation, and no sharing of project economics beyond the credit itself. This structural simplicity is a significant advantage for DEH, which retains sole ownership and control of the Project through DRI and RWE.

B. Transfer Pricing

The proposed transfer price is $0.92 per $1.00 of credit — that is, Pinnacle will pay 92 cents for each dollar of PTC transferred. This pricing reflects a discount of 8% from face value, which represents Pinnacle's economic return on the transaction. From Pinnacle's perspective, the transaction generates an immediate and risk-adjusted return: Pinnacle pays $0.92 and receives a $1.00 reduction in its federal income tax liability, netting $0.08 per dollar of credit.

The proposed transfer price of $0.92 per dollar is within the range currently observed in the market for wind PTCs under § 6418. Based on market intelligence gathered by C&H from other renewable energy credit transfer transactions closed in 2025 and early 2026, transfer prices for wind PTCs have generally ranged from $0.88 to $0.96 per dollar, depending on the following factors:

• Credit quality and project risk profile: Projects with established operating track records, contracted revenue streams (such as the Ridgeway Project's 20-year PPA with GPMPA), and creditworthy offtakers command higher transfer prices. Conversely, projects in development or early operations, or projects without long-term PPAs, tend to trade at wider discounts.

• Counterparty creditworthiness: The creditworthiness of the transferor entity and its parent company affects pricing, as the transferee relies on the transferor's representations, indemnification obligations, and ongoing compliance obligations. DEH's strong revenue base and established operations are expected to be viewed favorably by Pinnacle, partially offset by the Cayman incorporation and the limited visibility into DEH's overall financial position that is typical for privately held companies.

• Credit duration and volume: Multi-year, high-volume transactions — such as the proposed 10-year, approximately $253 million credit transfer — tend to command marginally tighter pricing than single-year or small-volume transfers, reflecting the transferee's preference for scale and the reduced per-unit transaction costs.

• Insurance and indemnification protections: The availability of recapture insurance and the scope of the transferor's indemnification obligations affect the transferee's perceived risk, which is reflected in the transfer price. The proposed transaction includes both a 15% indemnity holdback and recapture insurance from Northfield Specialty Insurance Co., which should support pricing at or near the upper end of the market range.

Based on these factors, C&H believes that the proposed transfer price of $0.92 per dollar is reasonable and within the range of arm's-length pricing for a transaction of this type and credit profile. However, we note that pricing is ultimately a commercial negotiation between the parties, and Pinnacle may seek to negotiate a lower price based on its own risk assessment and alternative investment opportunities.

Applying the proposed transfer price to the estimated annual PTC:

Estimated Year 1 transfer consideration: $25,295,655 × 0.92 = $23,271,803 (approximately $23.3 million)

Estimated 10-year aggregate transfer consideration (nominal): $253,000,000 × 0.92 = $232,760,000 (approximately $232.8 million)

C. Payment Timing and Mechanics

The Transfer Agreement will establish the payment timing and mechanics for each taxable year's transfer consideration. The proposed structure contemplates a lump-sum payment for each taxable year's estimated credits, payable within 30 days after the later of:

(a) the filing of DRI's IRS pre-filing registration for the applicable taxable year and receipt of a valid registration number from the IRS; and

(b) the annual true-up date, which is anticipated to be tied to the completion of Meridian's annual energy production report and the confirmation of actual electricity generation for the applicable taxable year.

The timing of payment is a critical structural element. The IRS registration number is a prerequisite for both the transferor and the transferee to claim the credit on their respective tax returns, and Pinnacle will not make payment until a valid registration number has been obtained. The annual energy production report provides the actual generation data needed to calculate the precise PTC amount for the taxable year.

Annual True-Up Mechanism: The Transfer Agreement will include an annual true-up mechanism to address the variability between estimated and actual electricity generation. For each taxable year, the initial transfer consideration payment will be based on the P50 estimate of annual generation (836,220,000 kWh). After the close of each taxable year, actual generation will be confirmed by Meridian based on SCADA data and settlement-quality meter readings. If actual generation exceeds or falls short of the P50 estimate, the PTC amount and the corresponding transfer consideration will be adjusted accordingly.

• If actual generation exceeds the P50 estimate, Pinnacle will pay DRI/RWE the incremental transfer consideration (calculated at $0.92 per dollar of additional PTC) within a specified period (e.g., 30 days) after the true-up determination.

• If actual generation falls short of the P50 estimate, the excess payment made by Pinnacle for the applicable taxable year will be credited against the following year's transfer consideration payment. In the final year of the 10-year PTC eligibility period (TY2034), any excess payment would be refunded by DRI/RWE to Pinnacle within a specified period.

The true-up mechanism is designed to ensure that Pinnacle pays only for the PTC actually generated and available for transfer in each taxable year, while providing DRI/RWE with timely receipt of transfer consideration based on expected production levels. The specific mechanics of the true-up — including the timing of the true-up determination, the deadline for incremental payments or credits, and the treatment of disputes regarding actual generation — will be negotiated in the Transfer Agreement.

D. Indemnity Holdback and Escrow

To protect Pinnacle against the risk of credit recapture, disallowance, or other adverse tax events attributable to the transferor's actions or omissions, the proposed structure includes an indemnity holdback and escrow arrangement.

Holdback Percentage: 15% of each annual transfer consideration payment will be withheld from the payment to DRI/RWE and deposited into an escrow account.

Year 1 Holdback Amount: $23,271,803 × 0.15 = $3,490,770

Escrow Agent: Commonwealth Fiduciary Trust Company, a Pennsylvania-chartered trust company with its principal office at One Liberty Place, 1650 Market Street, Suite 3600, Philadelphia, PA 19103. Commonwealth Fiduciary is a nationally recognized escrow agent with experience in tax credit transfer transactions and has been approved by both parties on a preliminary basis.

Holdback Release Period: Escrowed amounts will be held for a period of 36 months from the date of each escrow deposit. The 36-month holdback period is intended to provide a reasonable window for the identification and resolution of potential credit recapture events, IRS audit activity, or other claims that could give rise to indemnification obligations. This period corresponds roughly to the IRS's general three-year statute of limitations for tax assessments, although we note that the statute of limitations can be extended in certain circumstances (e.g., substantial omission of income, fraud, or extension by agreement).

Purpose: The holdback secures DRI/RWE's indemnification obligations to Pinnacle with respect to:

(i) Credit recapture events under IRC § 45, including cessation of qualified facility status or failure to produce electricity from a qualified energy resource;

(ii) Credit disallowance by the IRS, including (a) failure to satisfy prevailing wage requirements for post-COD alterations or repairs, (b) loss of energy community status for Custer County resulting from a determination that the status was incorrectly claimed (as distinguished from future-year loss of status, which is typically a transferee risk), and (c) challenge to the COD, placed-in-service date, or qualification of the facility; and

(iii) Breach of any seller representation or warranty in the Transfer Agreement.

Release Mechanics: After the expiration of the 36-month holdback period for each annual escrow deposit, the escrowed amounts (together with any investment earnings thereon) will be released to DRI/RWE, provided that no indemnity claims are then pending or unresolved. If any indemnity claims are pending as of the release date, a portion of the escrowed amounts equal to the reasonably estimated value of the pending claims will be retained in escrow until final resolution of such claims. The remaining escrowed amounts will be released to DRI/RWE. The specific claim procedures, notice requirements, dispute resolution mechanisms, and investment guidelines for the escrowed funds will be set forth in the Escrow Agreement described in Section XI.B below.

The 15% holdback percentage is within the range typically observed in § 6418 credit transfer transactions (generally 10%–20%), and the 36-month release period is standard market practice. C&H will advise on the negotiation of these terms in the context of the overall risk allocation framework of the Transfer Agreement.

VI. IRS Pre-Filing Registration Requirements

Under Treasury Regulations Section 1.6418-4, the eligible taxpayer making a transfer election under § 6418 must complete a pre-filing registration with the IRS for each taxable year in which a transfer election is made. The registration requirement is a mandatory prerequisite to the valid transfer of credits; failure to complete the registration renders the transfer election invalid, and neither the transferor nor the transferee may claim the credit.

Registration is filed electronically through the IRS Energy Credits Online portal, which was launched by the IRS in November 2023 and has been updated periodically since then to accommodate additional credit types and registration workflows. The portal requires the creation of an IRS Online Account by an authorized representative of the taxpayer.

The pre-filing registration must include the following information:

(a) Identification of the eligible taxpayer (DRI): Name, taxpayer identification number (EIN), address, taxable year, and type of entity. For DRI, this information is: Dunmore Renewables Inc., EIN [to be confirmed by Grayson Birch], 900 Bridger Boulevard, Suite 410, Billings, MT 59101, calendar taxable year, C corporation.

(b) Identification of the applicable entity (RWE): Because RWE is a disregarded entity, the registration must identify RWE as the entity that owns the qualified facility. The registration will include RWE's name, EIN (if separately assigned), and its relationship to DRI as a disregarded single-member LLC.

(d) Qualified facility information: The registration must describe the qualified facility in detail, including the facility name (Ridgeway Wind Project), location (Custer County, Montana), nameplate capacity (250 MW), type of qualified energy resource (wind), date construction began (April 6, 2023), and date placed in service (November 14, 2025).

(e) Identity of the transferee: The registration must identify the transferee taxpayer to whom the credit will be transferred, including Pinnacle Atlantic Partners LP's name, taxpayer identification number (EIN), address, and type of entity.

(f) Transfer amount: The registration must specify the amount of credit (or the percentage of the total credit) to be transferred for the applicable taxable year.

Upon submission and review of the registration, the IRS issues a unique registration number for each eligible credit and each taxable year. This registration number must be included on both the transferor's federal income tax return (Form 1120 for DRI, with attached Form 3800 and any applicable schedules) and the transferee's federal income tax return (Form 1065 for Pinnacle, with attached Form 3800). The registration number serves as the linking mechanism that enables the IRS to match the credit transferred by DRI with the credit claimed by Pinnacle.

Status of TY2025 Registration: Registration for TY2025 has not yet been filed. Grayson Birch & Co. LLP is responsible for preparing and filing the pre-filing registration on behalf of DRI through the IRS Energy Credits Online portal. Filing should be completed well in advance of the due date (including extensions) of DRI's TY2025 federal income tax return, which is September 15, 2026 (assuming DRI files on extension). However, because receipt of the registration number is a condition precedent to Pinnacle's payment obligation under the proposed Transfer Agreement, C&H recommends that the registration be filed as early as practicable — ideally no later than June 2026 — to avoid delays in the receipt of transfer consideration.

Transferee's Registration Obligation: Under Treasury Regulations Section 1.6418-4(b), the transferee (Pinnacle) must also complete a registration on the IRS Energy Credits Online portal and include the registration number on its federal income tax return for the taxable year in which it claims the transferred credit. Coordination with HL&S is required to ensure that Pinnacle's registration is completed concurrently with DRI's registration. The Transfer Agreement should include mutual covenants requiring each party to cooperate in the registration process and to complete its registration obligations within specified timeframes.

C&H will coordinate with Grayson Birch to ensure that the TY2025 registration is prepared accurately and filed in a timely manner, and will facilitate coordination with HL&S on the transferee-side registration.

VII. Recapture Risk Analysis

A. Recapture Events Under IRC § 45

PTCs claimed under IRC § 45 are subject to recapture in certain circumstances. The primary recapture risk for the Ridgeway Wind Project arises if the qualified facility ceases to qualify as a "qualified facility" during the 10-year PTC eligibility period — for example, if the facility ceases to produce electricity from a qualified energy resource (wind) or undergoes a change in ownership or use that causes it to fail to meet the requirements of § 45. Additionally, as discussed in Section IV.B above, the prevailing wage requirement of IRC § 45(b)(7) applies not only during construction but also to any alteration or repair of the facility during the credit period. Failure to satisfy the prevailing wage requirement for a post-COD alteration or repair would result in the loss of the 5x bonus multiplier for the applicable taxable year, which would significantly reduce the PTC and could trigger a recapture obligation if credits at the enhanced rate have already been claimed or transferred.

Under IRC § 6418(g), if a transferred credit is later recaptured, the transferee (Pinnacle) — not the transferor (DRI) — bears the recapture tax. This is a critical feature of the § 6418 framework: the statute places the recapture liability on the party that claimed the credit (the transferee), even though the recapture event may have been caused by the actions or omissions of the transferor. This statutory allocation of recapture risk is one of the primary reasons that transferees in § 6418 transactions require robust contractual indemnification from the transferor, as well as credit enhancement mechanisms such as holdbacks, escrows, and insurance.

From Pinnacle's perspective, the risk that a transferred credit is later recaptured or disallowed — and that Pinnacle would owe additional tax to the IRS — is the principal downside risk of the transaction. While Pinnacle can seek contractual indemnification from DRI/RWE, the effectiveness of that indemnification depends on DRI/RWE's financial capacity to honor its indemnification obligations when called upon. This counterparty credit risk is the reason for the indemnity holdback, the escrow, and the recapture insurance policy described in Section VII.C below.

B. Disallowance Risks

In addition to formal recapture events, several scenarios could result in the disallowance or reduction of PTCs for one or more taxable years:

(i) Failure to satisfy prevailing wage requirements for post-COD alterations or repairs. As noted, the prevailing wage requirement extends throughout the 10-year PTC eligibility period for any alteration or repair of the facility. RWE will be responsible for ensuring that all contractors and subcontractors performing maintenance, repair, or alteration work on the Project are paid at least the prevailing wage rates determined by the Department of Labor for the locality. This is an ongoing operational compliance obligation, and the risk of inadvertent non-compliance increases over the 10-year period as turbine components age and require more frequent maintenance. Under the IRA's correction and penalty provisions (IRC § 45(b)(7)(B)), a taxpayer that fails to satisfy the prevailing wage requirement may cure the failure by paying affected workers the difference between the prevailing wage and the amount actually paid, plus interest, and by paying a penalty to the IRS equal to $5,000 per worker per year (or $10,000 per worker per year in the case of intentional disregard). The availability of this correction mechanism mitigates, but does not eliminate, the risk of credit disallowance for prevailing wage violations.

(ii) Loss of energy community status for Custer County in subsequent taxable years. As discussed in Section IV.C, the energy community designation is subject to annual redetermination by Treasury and the IRS based on current economic data. If Custer County's statistical area no longer satisfies the fossil fuel employment and unemployment rate criteria in a future year, the 10% energy community bonus would be unavailable for that year. This would reduce the effective credit rate from $0.03025/kWh to $0.0275/kWh, reducing the annual PTC by approximately $2.3 million. The loss of the energy community bonus does not trigger a recapture of credits previously claimed at the enhanced rate — it only affects the credit rate for the year in which the designation is lost. As noted above, market practice generally allocates the risk of future-year loss of energy community status to the transferee, since it is a factor outside the transferor's control.

(iii) Reduction in actual electricity generation below estimated levels. If actual generation in a particular taxable year falls below the P50 estimate, the PTC for that year will be lower than the estimated amount used for the initial transfer consideration payment. This is not technically a "disallowance" — the credit is correctly calculated based on actual generation — but it results in a reduction in the credit available for transfer and a corresponding reduction in transfer consideration. This risk is addressed by the annual true-up mechanism described in Section V.C, which adjusts the transfer consideration to reflect actual generation.

(iv) IRS challenge to COD, placed-in-service date, or qualification of the facility. Although we believe the Ridgeway Wind Project satisfies all requirements for qualification as a qualified facility under IRC § 45(d) and that the COD of November 14, 2025 has been properly certified by Meridian, the IRS could challenge these determinations on audit. A successful challenge could result in the disallowance of all PTCs for the Project or a redetermination of the placed-in-service date that affects the credit period. This is a low-probability but high-impact risk. The Transfer Agreement should include representations by DRI/RWE regarding the qualification of the facility and the accuracy of the COD certification, and the indemnification provisions should cover losses arising from a successful IRS challenge to these determinations.

C. Risk Mitigation — Recapture Insurance

To mitigate the recapture and disallowance risks described above, DRI/RWE has retained Corbin Hale & Associates Inc. ("Corbin Hale") to procure a tax credit recapture insurance policy from Northfield Specialty Insurance Co. ("Northfield"). Corbin Hale is a specialized insurance brokerage firm focused on tax credit and renewable energy insurance products. The lead broker at Corbin Hale is Steven Rask, located at 200 South Wacker Drive, Suite 2800, Chicago, IL 60606. Northfield is a specialty insurer with its principal office at 80 Pine Street, New York, NY 10005, and is rated A (Excellent) by A.M. Best.

The recapture insurance policy would backstop DRI/RWE's indemnification obligations to Pinnacle in the event of a credit recapture or disallowance attributable to the transferor's actions or omissions. The policy is expected to cover losses arising from prevailing wage violations, erroneous COD determinations, and other specified disallowance events, subject to customary exclusions and deductibles.

The scope, coverage limits, exclusions, deductible, and premium for the policy are currently under negotiation between Corbin Hale and Northfield. As of the date of this memorandum, the key terms have not been finalized. Based on preliminary discussions, we understand that Corbin Hale is targeting a coverage limit of approximately $30 million to $40 million (approximately 12%–16% of the estimated 10-year aggregate PTC), with a deductible in the range of $500,000 to $1,000,000, and an annual premium estimated at approximately 1.5%–2.5% of the coverage limit. These terms are subject to Northfield's underwriting review, which is expected to include a review of the Grayson Birch prevailing wage compliance memorandum, the Meridian Energy Production Estimate and COD Certification, and the project documentation.

C&H recommends that the Transfer Agreement include a condition precedent to closing requiring Pinnacle's satisfaction with the terms of the recapture insurance policy. Pinnacle will likely require that the policy name Pinnacle as an additional insured or loss payee, and that DRI/RWE maintain the policy in effect throughout the PTC eligibility period (or until the expiration of the final indemnity holdback release period, if later). The Transfer Agreement should also include an ongoing covenant requiring DRI/RWE to maintain the insurance and to promptly notify Pinnacle of any claim, cancellation, or material modification of the policy.

VIII. Lender Consent Requirements — Redstone Capital Bank Credit Agreement

A. Section 7.14 Restriction

The Credit Agreement dated March 28, 2023, between RWE (as borrower) and Redstone Capital Bank, N.A. (as administrative agent and lender) contains a restrictive covenant in Section 7.14 that requires prior written consent of Redstone Capital Bank for any "transfer, sale, or assignment of tax attributes" generated by the Project. The defined term "tax attributes" in the Credit Agreement is broadly drafted and includes, without limitation, "tax credits, depreciation deductions, losses, and any other federal, state, or local tax benefit arising from or attributable to the Project or the Borrower's ownership or operation thereof."

The IRC § 6418 transfer of PTCs to Pinnacle clearly constitutes a transfer of "tax attributes" within the meaning of Section 7.14 and will require Redstone's prior written consent. Failure to obtain such consent before executing the Transfer Agreement and effectuating the § 6418 election would constitute an event of default under Section 8.01(d) of the Credit Agreement (breach of covenant), which could trigger acceleration of the outstanding loan balance ($271,600,000 as of March 1, 2026), enforcement of the lender's security interest in project assets, and other remedies available to Redstone under the Credit Agreement and applicable law.

Accordingly, obtaining Redstone's consent under Section 7.14 is a critical path item for the proposed transaction and must be secured before any definitive transaction documents are executed or any transfer election is made.

B. Depositary Agreement Waterfall Considerations

The Depositary Agreement dated March 28, 2023, between RWE and Redstone Capital Bank, N.A. establishes a revenue account waterfall governing the application of project revenues received by RWE. The waterfall prescribes the priority of distributions from the project revenue account, typically in the following order: (i) operating expenses, (ii) required debt service payments (principal and interest),

MEMORANDUM
PRIVILEGED AND CONFIDENTIAL — ATTORNEY-CLIENT COMMUNICATION
To: Marcus Petrov, Vice President, Tax, Dunmore Energy Holdings Ltd. Fiona Kessler, Chief Financial Officer, Dunmore Energy Holdings Ltd.
From: Sylvia Hartwell, Partner, Calderwood & Harkness LLP Robert Jansen, Associate, Calderwood & Harkness LLP
Date: March 24, 2026
Re: Structuring Memorandum — IRC § 6418 Transferable Credit Monetization for the Ridgeway Wind Project
Matter No.: 1016-00008
Billing Code: 09417.00001
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I. Executive Summary
The purpose of this memorandum is to set forth Calderwood & Harkness LLP's ("C&H") preliminary analysis of the proposed structure for monetizing Production Tax Credits ("PTCs") generated by the 250 MW Ridgeway Wind Project (the "Project") through a direct transfer election under Section 6418 of the Internal Revenue Code of 1986, as amended ("IRC" or the "Code"), as enacted by the Inflation Reduction Act of 2022 (Pub. L. No. 117-169) (the "IRA"). This memorandum identifies the key structural, legal, and tax considerations that DEH and its advisors should evaluate in connection with the proposed transaction.
Our client in this engagement is Dunmore Energy Holdings Ltd. ("DEH"), a Cayman Islands exempted limited company (registry number CR-284319), headquartered at 4th Floor, Harbour Place, 103 South Church Street, George Town, Grand Cayman KY1-1002, Cayman Islands. DEH is the ultimate parent entity of the project company.
The proposed transferor entity is Ridgeway Wind Energy LLC ("RWE"), a Delaware limited liability company (file number 7603517), which is wholly owned by Dunmore Renewables Inc. ("DRI"), a Delaware corporation (file number 7491826). DRI is in turn a wholly owned U.S. operating subsidiary of DEH. Because RWE is a single-member LLC that has not elected to be classified as a corporation for federal income tax purposes, RWE is a disregarded entity for U.S. federal income tax purposes. Accordingly, DRI is the regarded taxpayer that would claim PTCs generated by the Project and make the transfer election under IRC § 6418. As discussed in greater detail in Section III.A below, the analysis of whether the election is properly made by DRI or by RWE, given the disregarded entity status, is a threshold question that must be resolved before definitive documentation is prepared.
The prospective transferee is Pinnacle Atlantic Partners LP ("Pinnacle" or "PAP"), a Delaware limited partnership (file number 7255043), headquartered at 277 Park Row, 18th Floor, New York, NY 10172. Pinnacle is a large, diversified financial services firm with substantial federal income tax liability and significant experience in clean energy tax credit purchase transactions.
The primary rationale for pursuing a transfer under IRC § 6418 rather than direct utilization of the PTCs by DRI is that DEH has limited federal income tax liability due to legacy intangible drilling cost ("IDC") deductions and prior net operating losses ("NOLs"). These tax attributes substantially reduce the consolidated group's current federal income tax liability, rendering direct utilization of PTCs economically inefficient. A transfer under IRC § 6418 allows DEH and its subsidiaries to monetize the PTCs for cash consideration without entering into a traditional tax equity partnership flip structure, which would require the formation of a partnership, the admission of a tax equity investor, and the negotiation of complex partnership allocation provisions. The § 6418 transfer mechanism is considerably simpler from a structural perspective, preserves DRI's sole ownership of the Project through RWE, and avoids the governance and control complications inherent in tax equity transactions.
Based on the energy production estimate prepared by Meridian Technical Advisors LLC ("Meridian"), using a P50 net capacity factor of 38.2%, the estimated annual PTC for Year 1 (TY2025) is approximately $25,295,655. Over the 10-year PTC eligibility period (TY2025 through TY2034), the estimated aggregate PTC value is approximately $253,000,000 (nominal, pre-inflation adjustment). At the proposed transfer price of $0.92 per $1.00 of credit, the estimated 10-year aggregate transfer consideration payable by Pinnacle to DRI/RWE is approximately $232,760,000.
This engagement is currently in the prospective scoping phase. No definitive transaction documents have been negotiated or circulated. Pinnacle has delivered a non-binding indicative term sheet, which C&H has reviewed at a high level and will address in a separate commentary memorandum. This memorandum is intended to identify and analyze the key structural, legal, and tax considerations for the proposed transaction, and to recommend next steps for the client's evaluation.
The governing law for the proposed Transfer Agreement is expected to be New York. C&H is coordinating with Grayson Birch & Co. LLP ("Grayson Birch"), DEH's independent tax advisor, on PTC eligibility analysis, cost segregation, and IRS pre-filing registration matters. Howard Ellison is the lead partner at Grayson Birch responsible for these workstreams. In addition, Meridian Technical Advisors LLC (Dr. Paul Marlowe, PE, lead engineer) has prepared the energy production estimate and the commercial operations date ("COD") certification for the Project.
II. Background and Project Overview
A. Dunmore Energy Holdings Ltd. — Corporate Overview
DEH is a privately held energy company controlled by the Dunmore family. Callum Dunmore serves as Chairman of the board of directors and holds a 68% equity interest in DEH. The remaining equity interests are held by other members of the Dunmore family and certain long-tenured senior executives, the details of which are not material to this memorandum.
DEH's principal operations include upstream oil and gas exploration and production activities in the Permian Basin (spanning portions of West Texas and southeastern New Mexico), as well as a growing portfolio of renewable energy projects across the western United States. The renewable energy portfolio currently includes the Ridgeway Wind Project (the subject of this memorandum), two solar photovoltaic projects in development in Nevada and Arizona, and an early-stage battery energy storage project in Oregon. The transition toward renewable energy reflects both a strategic diversification initiative and a response to the favorable economics made available by the IRA's enhanced tax credit regime.
For the fiscal year ended December 31, 2025, DEH's consolidated revenue was approximately $1.34 billion. Notwithstanding this substantial revenue base, DEH's consolidated federal income tax liability has been significantly offset by legacy IDC deductions attributable to its upstream oil and gas operations, as well as NOLs carried forward from prior taxable years. This limited federal income tax liability is the primary driver for pursuing a § 6418 transfer of the Project's PTCs rather than direct credit utilization by DRI. Direct utilization would require sufficient federal income tax liability against which to apply the PTCs, and the current projections prepared by Grayson Birch indicate that DRI's share of federal income tax liability will be insufficient to fully absorb the annual PTC over the 10-year eligibility period. A transfer under § 6418 converts the credits to cash without requiring tax capacity at the transferor level.
B. Entity Structure
The relevant entity chain for the proposed transaction is as follows:
Dunmore Energy Holdings Ltd. (Cayman Islands exempted company, registry number CR-284319)
↓ 100% ownership
Dunmore Renewables Inc. (Delaware corporation, file number 7491826; principal office at 900 Bridger Boulevard, Suite 410, Billings, MT 59101)
↓ 100% sole member
Ridgeway Wind Energy LLC (Delaware limited liability company, file number 7603517; project company)
RWE is the sole owner and operator of the Ridgeway Wind Project and is the entity that generates and is entitled to the PTCs under IRC § 45. As noted above, RWE is a disregarded entity for U.S. federal income tax purposes because it is a single-member LLC that has not elected to be treated as a corporation under the "check-the-box" regulations (Treas. Reg. § 301.7701-3). Its sole member is DRI, a Delaware C corporation. Accordingly, for federal income tax purposes, all items of income, deduction, and credit generated by RWE are treated as items of DRI.
DRI is the taxpayer that would claim the PTCs on its federal income tax return and would make the transfer election under IRC § 6418. The analysis below addresses the interaction between the disregarded entity rules and the § 6418 election mechanics, including the IRS pre-filing registration requirements that require identification of both the regarded taxpayer (DRI) and the underlying eligible entity (RWE) that owns the qualified facility.
C. Ridgeway Wind Project
The following summarizes the key technical and commercial parameters of the Project:
Project Name: Ridgeway Wind Project
Location: The Project is situated on approximately 28,000 acres of leased ranchland located approximately 14 miles northeast of Miles City, in Custer County, Montana. The leasehold interests are held by RWE pursuant to a series of land lease agreements with five private landowners. The leases have initial terms of 40 years with renewal options, and are recorded with the Custer County Clerk and Recorder's Office.
Nameplate Capacity: 250 MW. The Project consists of 83 wind turbine generators, each with a rated capacity of 3.0 MW, totaling 249 MW, plus one additional 1.0 MW unit that serves as a substation backup generator. The turbines are General Electric Vernova 3.0-148 units with a rotor diameter of 148 meters and hub height of 105 meters.
Net Capacity Factor (P50): 38.2%, as determined by the energy production estimate prepared by Meridian Technical Advisors LLC, dated September 12, 2025 (the "Energy Production Estimate"). The P50 estimate represents the median expected annual energy production — that is, there is a 50% probability that actual production will equal or exceed this level. For purposes of financing and credit transfer structuring, the P50 figure is the standard benchmark used in the industry.
Construction Start Date: April 6, 2023. Construction commenced with the mobilization of earthwork equipment and the beginning of access road construction. This date is relevant to the determination of the beginning of construction under the IRA's transition rules for PTC-eligible facilities.
Commercial Operations Date (COD): November 14, 2025, as certified by Meridian in the COD Certification dated November 18, 2025. The COD Certification confirms that all 83 turbines (plus the backup unit) were mechanically complete, electrically interconnected to the grid, and capable of sustained commercial power generation as of November 14, 2025. For purposes of IRC § 45, the COD establishes the placed-in-service date of the facility and marks the beginning of the 10-year PTC eligibility period.
Total Project Cost: $412,000,000. This figure includes all hard costs (turbine procurement, balance of plant construction, electrical infrastructure, and interconnection facilities), soft costs (development fees, legal and advisory fees, permitting costs, and land lease prepayments), and capitalized interest during construction.
Financing:
•  Debt: $288,400,000 construction-to-term loan facility provided by Redstone Capital Bank, N.A. (OCC Charter No. 18742), representing a 70% loan-to-cost ratio ($412,000,000 × 0.70 = $288,400,000). The loan was originated as a construction facility and converted to a term loan upon achievement of COD in accordance with the terms of the Credit Agreement. The term loan has a maturity of 15 years from COD, a fixed interest rate of 5.875% per annum, and is secured by a first-priority lien on substantially all assets of RWE, including the turbines, leasehold interests, the PPA, and all project accounts.
•  Equity: $123,600,000 contributed by DRI, representing a 30% loan-to-cost ratio ($412,000,000 × 0.30 = $123,600,000). The equity was contributed in the form of cash capital contributions from DRI to RWE in installments corresponding to construction milestones.
Outstanding Loan Principal as of March 1, 2026: $271,600,000. Principal amortization of $16,800,000 has occurred since the loan's conversion to a term facility, reflecting scheduled amortization payments made in December 2025 and March 2026.
Credit Agreement and Depositary Agreement: Both dated March 28, 2023, between RWE (as borrower) and Redstone Capital Bank, N.A. (as administrative agent and lender), governed by New York law. The Credit Agreement contains customary project finance covenants, including a prohibition on transfers of tax attributes without prior lender consent (Section 7.14, discussed in detail in Section VIII below). The Depositary Agreement establishes the revenue account waterfall governing the application of project revenues, including debt service, reserve funding, and distribution provisions.
Power Purchase Agreement: RWE has entered into a 20-year fixed-price power purchase agreement with Great Plains Municipal Power Authority ("GPMPA") at a price of $38.50 per MWh. The PPA was executed on June 12, 2023. The contract term commences on the COD (November 14, 2025) and runs through November 13, 2045. GPMPA is a municipal power authority organized under Montana law that serves as the wholesale power supplier for approximately 14 member municipalities in central and eastern Montana. The PPA provides for the sale of all net energy output from the Project, with curtailment provisions and liquidated damages for failure to deliver minimum annual energy quantities.
Interconnection: The Project holds MISO Queue Position J-1147 and has executed a Generator Interconnection Agreement ("GIA") with NorthStar Transmission Holdings LLC, a Delaware limited liability company that owns and operates the transmission infrastructure in the relevant portion of the MISO transmission system. The GIA was executed on September 3, 2024, and provides for the interconnection of the Project at the Miles City 230 kV substation. The Project achieved full unrestricted interconnection service as of the COD.
III. Eligibility Analysis — IRC § 6418 Transfer Election
A. Eligible Taxpayer Status of the Transferor
Under IRC § 6418(a), as enacted by Section 13801 of the IRA, an "eligible taxpayer" that determines any "specified credit portion" for a taxable year may elect to transfer all or a portion of such credit to an unrelated transferee taxpayer for cash consideration. The election permits the transferor to monetize the credit without entering into a partnership structure with a tax equity investor, and without the transferor itself having sufficient federal income tax liability to utilize the credit.
The term "eligible taxpayer" is defined in IRC § 6418(f)(2) as any taxpayer other than (i) a tax-exempt entity described in IRC § 168(h)(2), or (ii) a governmental entity (i.e., any state or political subdivision thereof, the United States, any agency or instrumentality of the foregoing, or any Indian tribal government). DRI is a Delaware C corporation that is not tax-exempt and is not a governmental entity. Accordingly, DRI satisfies the definition of an "eligible taxpayer" for purposes of IRC § 6418.
The analysis of the transferor's eligible taxpayer status is complicated by the disregarded entity treatment of RWE. RWE is the entity that owns the qualified facility and generates the electricity from which PTCs arise. However, because RWE is disregarded for federal income tax purposes, all items of income, deduction, and credit attributable to RWE are treated as items of DRI, its sole member. Under Treasury Regulations Section 1.6418-2(a)(1), the transfer election under § 6418 is made by the taxpayer that would otherwise be entitled to claim the credit on its federal income tax return — in this case, DRI. The regulations further provide, however, that the pre-filing registration (discussed in Section VI) must identify both the regarded taxpayer (DRI) and the underlying "applicable entity" that owns the eligible property or qualified facility generating the credit. In this context, RWE is the applicable entity.
We note that the IRS issued final regulations under § 6418 on March 11, 2024 (T.D. 9993, 89 Fed. Reg. 17,548), which clarified the treatment of disregarded entities in the transfer election context. Under Treas. Reg. § 1.6418-2(a)(2), a disregarded entity is not treated as an "eligible taxpayer" for purposes of making the election; the election must be made by the regarded owner. However, the disregarded entity remains the "applicable entity" for purposes of identifying the facility and completing the pre-filing registration. This two-level identification requirement — regarded taxpayer as the electing party, disregarded entity as the facility owner — is consistent with the IRS's approach to the pre-filing registration portal and ensures that the IRS can match the credit to the specific facility generating the electricity.
Conclusion: DRI is the eligible taxpayer for purposes of the IRC § 6418 transfer election. RWE is the applicable entity that owns the qualified facility and generates the PTCs. The transfer election will be made by DRI on its timely filed federal income tax return for each taxable year in which PTCs are generated and transferred.
B. Specified Credit — Production Tax Credit Under IRC § 45
The PTC under IRC § 45 is a "specified credit portion" eligible for transfer under IRC § 6418(f)(1)(A). The IRA expanded the list of credits eligible for transfer under § 6418, and the PTC under § 45 is expressly included.
The Ridgeway Wind Project is a "qualified facility" under IRC § 45(d)(1), which defines a qualified facility for wind energy as any facility that uses wind to produce electricity and for which construction begins before January 1, 2025. Construction of the Ridgeway Wind Project commenced on April 6, 2023, which is after December 31, 2021 (the effective date of the IRA's enhanced PTC provisions) and before January 1, 2025. The facility was placed in service on November 14, 2025 (prior to January 1, 2026), satisfying the placed-in-service requirement for PTC eligibility.
Under the IRA's transition rules, a taxpayer may elect to claim either the PTC under § 45 or the Investment Tax Credit ("ITC") under § 48 for a qualified facility. DEH and Grayson Birch have performed a comparative analysis and determined that the PTC election is more favorable for the Ridgeway Wind Project given the Project's high capacity factor (38.2% P50) and the 10-year credit period. At a capacity factor of 38.2%, the present value of PTCs over the 10-year period exceeds the one-time ITC that would be available under § 48 based on the Project's eligible basis. This determination is consistent with industry practice for wind projects with capacity factors above approximately 30%, where the PTC generally provides greater economic value than the ITC.
We note that, under the IRA, new clean energy facilities placed in service after December 31, 2024 may alternatively be eligible for the technology-neutral clean electricity PTC under IRC § 45Y or the clean electricity ITC under § 48E. However, because the Ridgeway Wind Project commenced construction before January 1, 2025, and is a wind facility that qualifies under the legacy § 45 provisions, DEH and Grayson Birch have elected to claim PTCs under § 45 rather than § 45Y. This election is irrevocable once made for the first taxable year in which the credit is claimed.
C. Transferee Eligibility — Pinnacle Atlantic Partners LP
Under IRC § 6418(a), the transferee must be a taxpayer that is not related to the eligible taxpayer within the meaning of IRC § 267(b) or § 707(b)(1). These provisions define "related persons" broadly to include members of a family, entities under common control, and partnerships in which the same persons own more than 50% of the capital or profits interests.
Pinnacle Atlantic Partners LP is a Delaware limited partnership with no ownership, familial, or other relationship to DEH, DRI, RWE, or any member of the Dunmore family. C&H has conducted a preliminary review of the ownership structures of both DEH and Pinnacle and has identified no overlapping officers, directors, equity holders, or beneficial owners. Pinnacle's general partner is Pinnacle Atlantic GP Inc., a Delaware corporation, and its limited partners consist of various institutional investors, pension funds, and high-net-worth individuals, none of whom, to our knowledge, have any affiliation with the Dunmore family or DEH's affiliated entities. We recommend that both parties exchange officer, director, and beneficial owner lists and execute representations confirming the absence of any relationship described in IRC § 267(b) or § 707(b)(1) as a condition to closing.
Pinnacle has an average annual federal income tax liability of approximately $480,000,000 over the past three fiscal years (FY2023, FY2024, and FY2025), which is more than sufficient to absorb the estimated annual PTC of approximately $25.3 million. The ratio of Pinnacle's annual tax liability to the annual PTC is approximately 19:1, providing substantial headroom and eliminating any concern that Pinnacle might be unable to utilize the transferred credits in the year of transfer. Under IRC § 6418(d)(1), the transferred credit may not reduce the transferee's tax liability below zero — that is, the credit is non-refundable in the hands of the transferee. Given Pinnacle's substantial tax liability, this limitation is not expected to be a constraint.
Pinnacle has previously closed approximately $1.2 billion in IRC § 6418 credit purchases across solar, wind, and battery storage projects since the IRA's enactment, demonstrating institutional familiarity with the transfer mechanics, IRS registration requirements, and market documentation standards. This prior experience should facilitate an efficient negotiation and documentation process.
Pinnacle is represented by Hargrove, Liddell & Strauss LLP ("HL&S"), located at 400 Lexington Avenue, Suite 3200, New York, NY 10170. The lead contacts at HL&S are Nathaniel Strauss (partner, Tax) and Catherine Yoon (senior associate, Tax). C&H has previously transacted with HL&S on unrelated matters and anticipates a constructive working relationship on the documentation for this transaction.
IV. PTC Computation
A. Base Credit Rate
The base credit rate for the PTC under IRC § 45(a)(1) is $0.0055 per kilowatt-hour ("kWh") of electricity produced from a qualified energy resource at a qualified facility during the 10-year period beginning on the date the facility is placed in service. This rate reflects the inflation-adjusted base rate applicable to wind facilities placed in service in calendar year 2025, as published in IRS Notice 2025-XX (pending final publication) pursuant to the inflation adjustment mechanism set forth in IRC § 45(e)(2). The base rate is adjusted annually for inflation and rounded to the nearest 0.1 cent.
It is important to note that this base rate reflects the "non-enhanced" credit amount — that is, the credit rate available to facilities that do not satisfy the prevailing wage and apprenticeship requirements of IRC §§ 45(b)(7) and 45(b)(8). As discussed immediately below, the Ridgeway Wind Project has satisfied these requirements, entitling it to a 5x bonus multiplier that significantly increases the effective credit rate.
B. Bonus Credit Multiplier — Prevailing Wage and Apprenticeship Requirements
Under IRC § 45(b)(6)(B), the base credit rate is multiplied by five (5) if the qualified facility satisfies the prevailing wage and apprenticeship requirements set forth in IRC §§ 45(b)(7) and 45(b)(8), respectively. These requirements are as follows:
Prevailing Wage Requirement (IRC § 45(b)(7)): Any laborers and mechanics employed by the taxpayer or any contractor or subcontractor in the construction, alteration, or repair of the qualified facility must be paid wages at rates not less than the prevailing rates for construction, alteration, or repair of a similar character in the locality in which the facility is located, as determined by the Secretary of Labor in accordance with subchapter IV of chapter 31 of title 40, United States Code (the Davis-Bacon Act). This requirement applies both during construction and for any alteration or repair of the facility during the entire PTC eligibility period.
Apprenticeship Requirement (IRC § 45(b)(8)): The taxpayer must ensure that, with respect to the construction of the qualified facility, not less than the applicable percentage of total labor hours are performed by qualified apprentices. For facilities for which construction begins in 2023, the applicable percentage is 12.5%. Additionally, the taxpayer must comply with the ratio requirements (the ratio of apprentices to journeyworkers) established by the applicable registered apprenticeship program.
The Ridgeway Wind Project satisfied both the prevailing wage and apprenticeship requirements during the construction phase (April 6, 2023 through November 14, 2025). RWE's construction manager, Westland Infrastructure Group LLC, maintained certified payroll records demonstrating compliance with Davis-Bacon Act wage rates throughout the construction period, and the apprenticeship participation rate exceeded the 12.5% threshold. Grayson Birch & Co. LLP is currently preparing a detailed compliance memorandum confirming satisfaction of these requirements based on its review of the certified payroll records, apprenticeship certifications, and related documentation. C&H expects to receive a draft of this memorandum by approximately May 1, 2026.
It is critically important to note that the prevailing wage requirement extends beyond the construction phase and applies to any alteration or repair of the facility for the duration of the PTC eligibility period (TY2025 through TY2034). Failure to satisfy the prevailing wage requirement for any alteration or repair during this period could result in the loss of the 5x bonus multiplier for the applicable taxable year, thereby reducing the effective credit rate from $0.0275/kWh to $0.0055/kWh. The Transfer Agreement should include robust representations and covenants by DRI/RWE regarding ongoing prevailing wage compliance, and the indemnification provisions should address the transferee's exposure in the event of a failure to comply. This is a key risk factor that Pinnacle will likely focus on during negotiations.
Applying the 5x multiplier, the adjusted base credit rate is:
$0.0055 × 5 = $0.0275 per kWh
C. Energy Community Bonus Credit
Under IRC § 45(b)(11)(B), an additional 10% bonus credit applies if the qualified facility is located in an "energy community" as defined in IRC § 45(b)(11)(C). The energy community bonus is an additive enhancement to the credit — it increases the credit rate by 10% of the otherwise-applicable rate.
IRC § 45(b)(11)(C) defines "energy community" to include three categories of geographic areas:
(i) Brownfield sites as defined under certain provisions of the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA");
(ii) Metropolitan statistical areas or non-metropolitan statistical areas that have (or had at any time after December 31, 2009) 0.17% or greater direct employment or 25% or greater local tax revenues related to the extraction, processing, transport, or storage of coal, oil, or natural gas, and that have an unemployment rate at or above the national average; and
(iii) Census tracts (or directly adjoining census tracts) in which a coal mine has closed after December 31, 1999, or in which a coal-fired electric generating unit has been retired after December 31, 2009.
Custer County, Montana, where the Ridgeway Wind Project is located, qualifies as an energy community under the second category — IRC § 45(b)(11)(C)(iii) — based on historical fossil fuel employment levels in the county's statistical area. Custer County has a history of oil and gas extraction activity, and the relevant metropolitan or non-metropolitan statistical area has met the 0.17% direct employment threshold and the unemployment rate criterion in the most recently published IRS/Treasury guidance. The IRS published an updated list of qualifying energy communities in Notice 2024-30, which included the statistical area encompassing Custer County, Montana.
Applying the 10% energy community bonus, the effective credit rate is:
$0.0275 × 1.10 = $0.03025 per kWh
Important caveat: The energy community designation is subject to annual redetermination by the Treasury Department and the IRS. The unemployment rate component of the energy community test is based on data published by the Bureau of Labor Statistics, and changes in local employment conditions could cause Custer County's statistical area to lose its energy community qualification in a future taxable year. If the energy community bonus is lost for a particular taxable year, the effective credit rate for that year would revert to $0.0275/kWh (retaining the 5x prevailing wage/apprenticeship multiplier but losing the 10% energy community adder). This would reduce the annual PTC by approximately $2.3 million per year (approximately 10% of the full-rate PTC). Grayson Birch is monitoring the status of Custer County's qualification on an ongoing basis and will advise promptly if there is any indication that the designation may be at risk. The Transfer Agreement should allocate the risk of loss of energy community status between the parties — in most market transactions, the transferee bears the risk of future-year loss of energy community status (since it is outside the transferor's control), but the transferor indemnifies for any misrepresentation regarding the status as of the date of the Transfer Agreement.
D. Annual PTC Calculation
Based on the foregoing credit rate analysis and the energy production estimate prepared by Meridian, the estimated annual PTC for Year 1 (TY2025) is calculated as follows:
Nameplate capacity: 250 MW
Annual hours: 8,760 hours (non-leap year)
P50 net capacity factor: 38.2%
Estimated annual electricity generation: 250 MW × 8,760 hours × 0.382 = 836,220 MWh = 836,220,000 kWh
Effective PTC rate: $0.03025 per kWh
Estimated annual PTC (Year 1, TY2025): 836,220,000 kWh × $0.03025/kWh = $25,295,655
We note that an earlier estimate of approximately $34.65 million per year was reflected in certain preliminary marketing materials that were prepared by DRI's business development team using a higher capacity factor assumption (approximately 52%). That earlier estimate was based on a pre-construction resource assessment and did not incorporate the site-specific adjustments, turbine performance curves, and wake loss factors that are reflected in Meridian's final Energy Production Estimate. The P50-based figure of approximately $25.3 million per year is the canonical calculation for purposes of this structuring analysis and for the pricing discussions with Pinnacle. All references to PTC amounts in this memorandum and in subsequent transaction documents should use the Meridian P50-based estimate as the baseline.
E. 10-Year PTC Eligibility Period
Under IRC § 45(a)(2)(A)(ii), PTCs are available for electricity produced and sold by the taxpayer during the 10-year period beginning on the date the qualified facility is placed in service. For the Ridgeway Wind Project, this period runs from the placed-in-service date of November 14, 2025 through November 13, 2035, covering taxable years 2025 through 2034 for DRI (assuming DRI uses a calendar year as its taxable year, which we understand to be the case).
The estimated 10-year aggregate PTC, calculated on a nominal basis and without adjustment for annual inflation, is:
$25,295,655 × 10 ≈ $253,000,000 (rounded)
This figure is subject to annual inflation adjustments under IRC § 45(e)(2), which may increase or decrease the credit rate in each subsequent taxable year relative to the base year. The inflation adjustment is based on the GDP implicit price deflator published by the Bureau of Economic Analysis and is applied to the base credit rate before application of the 5x multiplier and the energy community bonus. In an inflationary environment, the actual 10-year aggregate PTC could exceed $253 million; in a deflationary or low-inflation environment, it could be lower. For purposes of the transfer pricing analysis in Section V, we use the nominal, unadjusted figure of $253 million as the baseline.
Additionally, the actual annual PTC will vary based on actual electricity generation, which will differ from the P50 estimate in any given year due to wind resource variability, turbine availability, curtailment events, and other operational factors. The annual true-up mechanism described in Section V.C is designed to address this variability.
V. Proposed Transfer Structure and Economics
A. Transfer Mechanism
The proposed transaction will be structured as a direct transfer election under IRC § 6418(a). DRI, as the regarded taxpayer and the eligible taxpayer for purposes of the transfer election, will elect to transfer the specified credit portion — i.e., the PTCs generated by the Ridgeway Wind Project — to Pinnacle for cash consideration.
The transfer mechanism under § 6418 is conceptually straightforward. For each taxable year in which the Ridgeway Wind Project generates PTCs, DRI will make an election on its timely filed (including extensions) federal income tax return to transfer all (or a portion, if applicable) of the PTCs to Pinnacle. Upon the making of this election and receipt of a valid IRS registration number, the credit is treated as if the transferee taxpayer (Pinnacle) were allowed the credit directly for the taxable year in which the credit was determined with respect to the transferor. The election is irrevocable for the taxable year in which it is made.
Critically, the transfer under § 6418 is not treated as a sale or exchange for federal income tax purposes. IRC § 6418(b)(4) provides that the transfer of a specified credit portion shall not be treated as a sale or other disposition of property. This has important consequences for both parties, as discussed in Section IX below.
The transfer of credits under § 6418 is fundamentally different from a traditional tax equity partnership flip structure. In a partnership flip, a tax equity investor acquires a partnership interest in the project company and is allocated tax credits and depreciation deductions through the partnership tax allocation provisions. The partnership flip structure involves complex partnership agreement negotiations, issues of economic substance, capital account maintenance, qualified income offset provisions, deficit restoration obligations, and the various safe harbors established by IRS guidance (including Revenue Procedure 2007-65 for wind projects). The § 6418 transfer, by contrast, is a simple two-party transaction in which credits are transferred for cash, with no equity investment, no partnership formation, and no sharing of project economics beyond the credit itself. This structural simplicity is a significant advantage for DEH, which retains sole ownership and control of the Project through DRI and RWE.
B. Transfer Pricing
The proposed transfer price is $0.92 per $1.00 of credit — that is, Pinnacle will pay 92 cents for each dollar of PTC transferred. This pricing reflects a discount of 8% from face value, which represents Pinnacle's economic return on the transaction. From Pinnacle's perspective, the transaction generates an immediate and risk-adjusted return: Pinnacle pays $0.92 and receives a $1.00 reduction in its federal income tax liability, netting $0.08 per dollar of credit.
The proposed transfer price of $0.92 per dollar is within the range currently observed in the market for wind PTCs under § 6418. Based on market intelligence gathered by C&H from other renewable energy credit transfer transactions closed in 2025 and early 2026, transfer prices for wind PTCs have generally ranged from $0.88 to $0.96 per dollar, depending on the following factors:
•  Credit quality and project risk profile: Projects with established operating track records, contracted revenue streams (such as the Ridgeway Project's 20-year PPA with GPMPA), and creditworthy offtakers command higher transfer prices. Conversely, projects in development or early operations, or projects without long-term PPAs, tend to trade at wider discounts.
•  Counterparty creditworthiness: The creditworthiness of the transferor entity and its parent company affects pricing, as the transferee relies on the transferor's representations, indemnification obligations, and ongoing compliance obligations. DEH's strong revenue base and established operations are expected to be viewed favorably by Pinnacle, partially offset by the Cayman incorporation and the limited visibility into DEH's overall financial position that is typical for privately held companies.
•  Credit duration and volume: Multi-year, high-volume transactions — such as the proposed 10-year, approximately $253 million credit transfer — tend to command marginally tighter pricing than single-year or small-volume transfers, reflecting the transferee's preference for scale and the reduced per-unit transaction costs.
•  Insurance and indemnification protections: The availability of recapture insurance and the scope of the transferor's indemnification obligations affect the transferee's perceived risk, which is reflected in the transfer price. The proposed transaction includes both a 15% indemnity holdback and recapture insurance from Northfield Specialty Insurance Co., which should support pricing at or near the upper end of the market range.
Based on these factors, C&H believes that the proposed transfer price of $0.92 per dollar is reasonable and within the range of arm's-length pricing for a transaction of this type and credit profile. However, we note that pricing is ultimately a commercial negotiation between the parties, and Pinnacle may seek to negotiate a lower price based on its own risk assessment and alternative investment opportunities.
Applying the proposed transfer price to the estimated annual PTC:
Estimated Year 1 transfer consideration: $25,295,655 × 0.92 = $23,271,803 (approximately $23.3 million)
Estimated 10-year aggregate transfer consideration (nominal): $253,000,000 × 0.92 = $232,760,000 (approximately $232.8 million)
C. Payment Timing and Mechanics
The Transfer Agreement will establish the payment timing and mechanics for each taxable year's transfer consideration. The proposed structure contemplates a lump-sum payment for each taxable year's estimated credits, payable within 30 days after the later of:
(a) the filing of DRI's IRS pre-filing registration for the applicable taxable year and receipt of a valid registration number from the IRS; and
(b) the annual true-up date, which is anticipated to be tied to the completion of Meridian's annual energy production report and the confirmation of actual electricity generation for the applicable taxable year.
The timing of payment is a critical structural element. The IRS registration number is a prerequisite for both the transferor and the transferee to claim the credit on their respective tax returns, and Pinnacle will not make payment until a valid registration number has been obtained. The annual energy production report provides the actual generation data needed to calculate the precise PTC amount for the taxable year.
Annual True-Up Mechanism: The Transfer Agreement will include an annual true-up mechanism to address the variability between estimated and actual electricity generation. For each taxable year, the initial transfer consideration payment will be based on the P50 estimate of annual generation (836,220,000 kWh). After the close of each taxable year, actual generation will be confirmed by Meridian based on SCADA data and settlement-quality meter readings. If actual generation exceeds or falls short of the P50 estimate, the PTC amount and the corresponding transfer consideration will be adjusted accordingly.
•  If actual generation exceeds the P50 estimate, Pinnacle will pay DRI/RWE the incremental transfer consideration (calculated at $0.92 per dollar of additional PTC) within a specified period (e.g., 30 days) after the true-up determination.
•  If actual generation falls short of the P50 estimate, the excess payment made by Pinnacle for the applicable taxable year will be credited against the following year's transfer consideration payment. In the final year of the 10-year PTC eligibility period (TY2034), any excess payment would be refunded by DRI/RWE to Pinnacle within a specified period.
The true-up mechanism is designed to ensure that Pinnacle pays only for the PTC actually generated and available for transfer in each taxable year, while providing DRI/RWE with timely receipt of transfer consideration based on expected production levels. The specific mechanics of the true-up — including the timing of the true-up determination, the deadline for incremental payments or credits, and the treatment of disputes regarding actual generation — will be negotiated in the Transfer Agreement.
D. Indemnity Holdback and Escrow
To protect Pinnacle against the risk of credit recapture, disallowance, or other adverse tax events attributable to the transferor's actions or omissions, the proposed structure includes an indemnity holdback and escrow arrangement.
Holdback Percentage: 15% of each annual transfer consideration payment will be withheld from the payment to DRI/RWE and deposited into an escrow account.
Year 1 Holdback Amount: $23,271,803 × 0.15 = $3,490,770
Escrow Agent: Commonwealth Fiduciary Trust Company, a Pennsylvania-chartered trust company with its principal office at One Liberty Place, 1650 Market Street, Suite 3600, Philadelphia, PA 19103. Commonwealth Fiduciary is a nationally recognized escrow agent with experience in tax credit transfer transactions and has been approved by both parties on a preliminary basis.
Holdback Release Period: Escrowed amounts will be held for a period of 36 months from the date of each escrow deposit. The 36-month holdback period is intended to provide a reasonable window for the identification and resolution of potential credit recapture events, IRS audit activity, or other claims that could give rise to indemnification obligations. This period corresponds roughly to the IRS's general three-year statute of limitations for tax assessments, although we note that the statute of limitations can be extended in certain circumstances (e.g., substantial omission of income, fraud, or extension by agreement).
Purpose: The holdback secures DRI/RWE's indemnification obligations to Pinnacle with respect to:
(i) Credit recapture events under IRC § 45, including cessation of qualified facility status or failure to produce electricity from a qualified energy resource;
(ii) Credit disallowance by the IRS, including (a) failure to satisfy prevailing wage requirements for post-COD alterations or repairs, (b) loss of energy community status for Custer County resulting from a determination that the status was incorrectly claimed (as distinguished from future-year loss of status, which is typically a transferee risk), and (c) challenge to the COD, placed-in-service date, or qualification of the facility; and
(iii) Breach of any seller representation or warranty in the Transfer Agreement.
Release Mechanics: After the expiration of the 36-month holdback period for each annual escrow deposit, the escrowed amounts (together with any investment earnings thereon) will be released to DRI/RWE, provided that no indemnity claims are then pending or unresolved. If any indemnity claims are pending as of the release date, a portion of the escrowed amounts equal to the reasonably estimated value of the pending claims will be retained in escrow until final resolution of such claims. The remaining escrowed amounts will be released to DRI/RWE. The specific claim procedures, notice requirements, dispute resolution mechanisms, and investment guidelines for the escrowed funds will be set forth in the Escrow Agreement described in Section XI.B below.
The 15% holdback percentage is within the range typically observed in § 6418 credit transfer transactions (generally 10%–20%), and the 36-month release period is standard market practice. C&H will advise on the negotiation of these terms in the context of the overall risk allocation framework of the Transfer Agreement.
VI. IRS Pre-Filing Registration Requirements
Under Treasury Regulations Section 1.6418-4, the eligible taxpayer making a transfer election under § 6418 must complete a pre-filing registration with the IRS for each taxable year in which a transfer election is made. The registration requirement is a mandatory prerequisite to the valid transfer of credits; failure to complete the registration renders the transfer election invalid, and neither the transferor nor the transferee may claim the credit.
Registration is filed electronically through the IRS Energy Credits Online portal, which was launched by the IRS in November 2023 and has been updated periodically since then to accommodate additional credit types and registration workflows. The portal requires the creation of an IRS Online Account by an authorized representative of the taxpayer.
The pre-filing registration must include the following information:
(a) Identification of the eligible taxpayer (DRI): Name, taxpayer identification number (EIN), address, taxable year, and type of entity. For DRI, this information is: Dunmore Renewables Inc., EIN [to be confirmed by Grayson Birch], 900 Bridger Boulevard, Suite 410, Billings, MT 59101, calendar taxable year, C corporation.
(b) Identification of the applicable entity (RWE): Because RWE is a disregarded entity, the registration must identify RWE as the entity that owns the qualified facility. The registration will include RWE's name, EIN (if separately assigned), and its relationship to DRI as a disregarded single-member LLC.
(c) Type of credit: Production Tax Credit under IRC § 45.
(d) Qualified facility information: The registration must describe the qualified facility in detail, including the facility name (Ridgeway Wind Project), location (Custer County, Montana), nameplate capacity (250 MW), type of qualified energy resource (wind), date construction began (April 6, 2023), and date placed in service (November 14, 2025).
(e) Identity of the transferee: The registration must identify the transferee taxpayer to whom the credit will be transferred, including Pinnacle Atlantic Partners LP's name, taxpayer identification number (EIN), address, and type of entity.
(f) Transfer amount: The registration must specify the amount of credit (or the percentage of the total credit) to be transferred for the applicable taxable year.
Upon submission and review of the registration, the IRS issues a unique registration number for each eligible credit and each taxable year. This registration number must be included on both the transferor's federal income tax return (Form 1120 for DRI, with attached Form 3800 and any applicable schedules) and the transferee's federal income tax return (Form 1065 for Pinnacle, with attached Form 3800). The registration number serves as the linking mechanism that enables the IRS to match the credit transferred by DRI with the credit claimed by Pinnacle.
Status of TY2025 Registration: Registration for TY2025 has not yet been filed. Grayson Birch & Co. LLP is responsible for preparing and filing the pre-filing registration on behalf of DRI through the IRS Energy Credits Online portal. Filing should be completed well in advance of the due date (including extensions) of DRI's TY2025 federal income tax return, which is September 15, 2026 (assuming DRI files on extension). However, because receipt of the registration number is a condition precedent to Pinnacle's payment obligation under the proposed Transfer Agreement, C&H recommends that the registration be filed as early as practicable — ideally no later than June 2026 — to avoid delays in the receipt of transfer consideration.
Transferee's Registration Obligation: Under Treasury Regulations Section 1.6418-4(b), the transferee (Pinnacle) must also complete a registration on the IRS Energy Credits Online portal and include the registration number on its federal income tax return for the taxable year in which it claims the transferred credit. Coordination with HL&S is required to ensure that Pinnacle's registration is completed concurrently with DRI's registration. The Transfer Agreement should include mutual covenants requiring each party to cooperate in the registration process and to complete its registration obligations within specified timeframes.
C&H will coordinate with Grayson Birch to ensure that the TY2025 registration is prepared accurately and filed in a timely manner, and will facilitate coordination with HL&S on the transferee-side registration.
VII. Recapture Risk Analysis
A. Recapture Events Under IRC § 45
PTCs claimed under IRC § 45 are subject to recapture in certain circumstances. The primary recapture risk for the Ridgeway Wind Project arises if the qualified facility ceases to qualify as a "qualified facility" during the 10-year PTC eligibility period — for example, if the facility ceases to produce electricity from a qualified energy resource (wind) or undergoes a change in ownership or use that causes it to fail to meet the requirements of § 45. Additionally, as discussed in Section IV.B above, the prevailing wage requirement of IRC § 45(b)(7) applies not only during construction but also to any alteration or repair of the facility during the credit period. Failure to satisfy the prevailing wage requirement for a post-COD alteration or repair would result in the loss of the 5x bonus multiplier for the applicable taxable year, which would significantly reduce the PTC and could trigger a recapture obligation if credits at the enhanced rate have already been claimed or transferred.
Under IRC § 6418(g), if a transferred credit is later recaptured, the transferee (Pinnacle) — not the transferor (DRI) — bears the recapture tax. This is a critical feature of the § 6418 framework: the statute places the recapture liability on the party that claimed the credit (the transferee), even though the recapture event may have been caused by the actions or omissions of the transferor. This statutory allocation of recapture risk is one of the primary reasons that transferees in § 6418 transactions require robust contractual indemnification from the transferor, as well as credit enhancement mechanisms such as holdbacks, escrows, and insurance.
From Pinnacle's perspective, the risk that a transferred credit is later recaptured or disallowed — and that Pinnacle would owe additional tax to the IRS — is the principal downside risk of the transaction. While Pinnacle can seek contractual indemnification from DRI/RWE, the effectiveness of that indemnification depends on DRI/RWE's financial capacity to honor its indemnification obligations when called upon. This counterparty credit risk is the reason for the indemnity holdback, the escrow, and the recapture insurance policy described in Section VII.C below.
B. Disallowance Risks
In addition to formal recapture events, several scenarios could result in the disallowance or reduction of PTCs for one or more taxable years:
(i) Failure to satisfy prevailing wage requirements for post-COD alterations or repairs. As noted, the prevailing wage requirement extends throughout the 10-year PTC eligibility period for any alteration or repair of the facility. RWE will be responsible for ensuring that all contractors and subcontractors performing maintenance, repair, or alteration work on the Project are paid at least the prevailing wage rates determined by the Department of Labor for the locality. This is an ongoing operational compliance obligation, and the risk of inadvertent non-compliance increases over the 10-year period as turbine components age and require more frequent maintenance. Under the IRA's correction and penalty provisions (IRC § 45(b)(7)(B)), a taxpayer that fails to satisfy the prevailing wage requirement may cure the failure by paying affected workers the difference between the prevailing wage and the amount actually paid, plus interest, and by paying a penalty to the IRS equal to $5,000 per worker per year (or $10,000 per worker per year in the case of intentional disregard). The availability of this correction mechanism mitigates, but does not eliminate, the risk of credit disallowance for prevailing wage violations.
(ii) Loss of energy community status for Custer County in subsequent taxable years. As discussed in Section IV.C, the energy community designation is subject to annual redetermination by Treasury and the IRS based on current economic data. If Custer County's statistical area no longer satisfies the fossil fuel employment and unemployment rate criteria in a future year, the 10% energy community bonus would be unavailable for that year. This would reduce the effective credit rate from $0.03025/kWh to $0.0275/kWh, reducing the annual PTC by approximately $2.3 million. The loss of the energy community bonus does not trigger a recapture of credits previously claimed at the enhanced rate — it only affects the credit rate for the year in which the designation is lost. As noted above, market practice generally allocates the risk of future-year loss of energy community status to the transferee, since it is a factor outside the transferor's control.
(iii) Reduction in actual electricity generation below estimated levels. If actual generation in a particular taxable year falls below the P50 estimate, the PTC for that year will be lower than the estimated amount used for the initial transfer consideration payment. This is not technically a "disallowance" — the credit is correctly calculated based on actual generation — but it results in a reduction in the credit available for transfer and a corresponding reduction in transfer consideration. This risk is addressed by the annual true-up mechanism described in Section V.C, which adjusts the transfer consideration to reflect actual generation.
(iv) IRS challenge to COD, placed-in-service date, or qualification of the facility. Although we believe the Ridgeway Wind Project satisfies all requirements for qualification as a qualified facility under IRC § 45(d) and that the COD of November 14, 2025 has been properly certified by Meridian, the IRS could challenge these determinations on audit. A successful challenge could result in the disallowance of all PTCs for the Project or a redetermination of the placed-in-service date that affects the credit period. This is a low-probability but high-impact risk. The Transfer Agreement should include representations by DRI/RWE regarding the qualification of the facility and the accuracy of the COD certification, and the indemnification provisions should cover losses arising from a successful IRS challenge to these determinations.
C. Risk Mitigation — Recapture Insurance
To mitigate the recapture and disallowance risks described above, DRI/RWE has retained Corbin Hale & Associates Inc. ("Corbin Hale") to procure a tax credit recapture insurance policy from Northfield Specialty Insurance Co. ("Northfield"). Corbin Hale is a specialized insurance brokerage firm focused on tax credit and renewable energy insurance products. The lead broker at Corbin Hale is Steven Rask, located at 200 South Wacker Drive, Suite 2800, Chicago, IL 60606. Northfield is a specialty insurer with its principal office at 80 Pine Street, New York, NY 10005, and is rated A (Excellent) by A.M. Best.
The recapture insurance policy would backstop DRI/RWE's indemnification obligations to Pinnacle in the event of a credit recapture or disallowance attributable to the transferor's actions or omissions. The policy is expected to cover losses arising from prevailing wage violations, erroneous COD determinations, and other specified disallowance events, subject to customary exclusions and deductibles.
The scope, coverage limits, exclusions, deductible, and premium for the policy are currently under negotiation between Corbin Hale and Northfield. As of the date of this memorandum, the key terms have not been finalized. Based on preliminary discussions, we understand that Corbin Hale is targeting a coverage limit of approximately $30 million to $40 million (approximately 12%–16% of the estimated 10-year aggregate PTC), with a deductible in the range of $500,000 to $1,000,000, and an annual premium estimated at approximately 1.5%–2.5% of the coverage limit. These terms are subject to Northfield's underwriting review, which is expected to include a review of the Grayson Birch prevailing wage compliance memorandum, the Meridian Energy Production Estimate and COD Certification, and the project documentation.
C&H recommends that the Transfer Agreement include a condition precedent to closing requiring Pinnacle's satisfaction with the terms of the recapture insurance policy. Pinnacle will likely require that the policy name Pinnacle as an additional insured or loss payee, and that DRI/RWE maintain the policy in effect throughout the PTC eligibility period (or until the expiration of the final indemnity holdback release period, if later). The Transfer Agreement should also include an ongoing covenant requiring DRI/RWE to maintain the insurance and to promptly notify Pinnacle of any claim, cancellation, or material modification of the policy.
VIII. Lender Consent Requirements — Redstone Capital Bank Credit Agreement
A. Section 7.14 Restriction
The Credit Agreement dated March 28, 2023, between RWE (as borrower) and Redstone Capital Bank, N.A. (as administrative agent and lender) contains a restrictive covenant in Section 7.14 that requires prior written consent of Redstone Capital Bank for any "transfer, sale, or assignment of tax attributes" generated by the Project. The defined term "tax attributes" in the Credit Agreement is broadly drafted and includes, without limitation, "tax credits, depreciation deductions, losses, and any other federal, state, or local tax benefit arising from or attributable to the Project or the Borrower's ownership or operation thereof."
The IRC § 6418 transfer of PTCs to Pinnacle clearly constitutes a transfer of "tax attributes" within the meaning of Section 7.14 and will require Redstone's prior written consent. Failure to obtain such consent before executing the Transfer Agreement and effectuating the § 6418 election would constitute an event of default under Section 8.01(d) of the Credit Agreement (breach of covenant), which could trigger acceleration of the outstanding loan balance ($271,600,000 as of March 1, 2026), enforcement of the lender's security interest in project assets, and other remedies available to Redstone under the Credit Agreement and applicable law.
Accordingly, obtaining Redstone's consent under Section 7.14 is a critical path item for the proposed transaction and must be secured before any definitive transaction documents are executed or any transfer election is made.
B. Depositary Agreement Waterfall Considerations
The Depositary Agreement dated March 28, 2023, between RWE and Redstone Capital Bank, N.A. establishes a revenue account waterfall governing the application of project revenues received by RWE. The waterfall prescribes the priority of distributions from the project revenue account, typically in the following order: (i) operating expenses, (ii) required debt service payments (principal and interest),

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