CALDERWOOD & HARKNESS LLP 700 Fifth Avenue, 33rd Floor New York, NY 10019
ATTORNEY WORK PRODUCT — PRIVILEGED & CONFIDENTIAL
Preliminary Issues List — Ridgeway Wind Project PTC Transfer
This memorandum constitutes attorney work product prepared in anticipation of litigation or for the purpose of rendering legal advice and is protected by the attorney-client privilege and the work-product doctrine. This document is intended solely for the use of Calderwood & Harkness LLP attorneys and personnel working on the referenced matter and, upon approval by the responsible partner, for authorized client representatives. This document should not be disclosed to any third party without the prior written consent of Calderwood & Harkness LLP.
Introduction and Purpose
This working issues list identifies open legal, tax, structural, and regulatory issues requiring resolution in connection with the proposed direct transfer election under Section 6418 of the Internal Revenue Code of 1986, as amended (the "Code" or "IRC"), for Production Tax Credits ("PTCs") generated by the 250 MW Ridgeway Wind Project (the "Project" or the "Ridgeway Wind Project"). The purpose of this document is to provide the engagement team and, upon approval, the client with a comprehensive inventory of the issues that must be addressed during the scoping, structuring, and documentation phases of this transaction. It is not intended to provide definitive analysis of any issue but rather to frame the questions and identify the work streams necessary to bring each issue to resolution.
Transferor. The transferor of the PTCs is Ridgeway Wind Energy LLC, a Delaware limited liability company (Delaware Secretary of State file number 7603517) ("Ridgeway Wind" or the "Project Company"). Ridgeway Wind is a single-member limited liability company whose sole member is Dunmore Renewables Inc., a Delaware corporation (Delaware Secretary of State file number 7491826) ("DRI" or "Dunmore Renewables"). Ridgeway Wind is treated as a disregarded entity for federal income tax purposes. DRI is, in turn, an indirect wholly owned subsidiary of Dunmore Energy Holdings Ltd., a Cayman Islands exempted limited company (Cayman Islands Registrar of Companies registry number CR-284319) ("DEH" or "Dunmore Energy Holdings"). References to the "Client" in this issues list refer collectively to DEH, DRI, and Ridgeway Wind, as the context requires.
Proposed Transferee. The proposed transferee of the PTCs is Pinnacle Atlantic Partners LP, a Delaware limited partnership (Delaware Secretary of State file number 7255043), headquartered at 277 Park Row, 18th Floor, New York, NY 10172 ("Pinnacle" or the "Buyer"). Pinnacle is represented by Hargrove, Liddell & Strauss LLP ("HL&S"), with Nathaniel Strauss serving as lead partner and Catherine Yoon serving as senior associate on this matter. Based on publicly available information and representations made during preliminary discussions, Pinnacle has closed approximately $1.2 billion in prior IRC § 6418 credit purchase transactions across multiple renewable energy asset classes.
Engagement Status. This engagement is currently in the scoping phase. The engagement was formally opened on March 9, 2026, pursuant to an engagement letter executed by Marcus Petrov, Vice President, Tax, Dunmore Energy Holdings Ltd., and countersigned by Sylvia Hartwell on behalf of Calderwood & Harkness LLP. No definitive transaction documents have been negotiated or exchanged as of the date of this issues list, although an indicative term sheet has been provided by Pinnacle. A document request was transmitted to the Client on March 10, 2026, and document production is underway. A structuring memorandum addressing the economic analysis and optimal transaction structure is being prepared under separate cover and will be delivered to the engagement team and Client upon completion.
Organization. This issues list is organized into the following categories:
I. Tax Credit Eligibility and Compliance
II. Lender Consent and Financing Considerations
III. Transfer Agreement Terms and Commercial Structure
IV. IRS Registration and Procedural Requirements
V. Entity Structure and Withholding
VI. Advisor Coordination and Diligence Work Streams
VII. Additional Open Items and Next Steps
Each category contains one or more numbered issues, with sub-issues identified where applicable. A summary table of all issues, with priority designations and status, is provided at the conclusion of this document. This issues list will be updated periodically as diligence progresses, as new issues are identified, and as existing issues are resolved or narrowed.
I. Tax Credit Eligibility and Compliance
Issue 1: Confirmation of Prevailing Wage and Apprenticeship Compliance for 5x Bonus Credit Multiplier
The Ridgeway Wind Project's PTC calculation is premised on the availability of the five-times (5x) bonus credit multiplier under IRC § 45(b)(6), as enacted by the Inflation Reduction Act of 2022 ("IRA"). The 5x multiplier is available only if the Project satisfies both the prevailing wage requirements and the apprenticeship requirements set forth in IRC § 45(b)(7) and (8), respectively. These requirements apply to both the construction of the facility and, in the case of prevailing wage, to the alteration and repair of the facility during the PTC eligibility period.
The economic significance of the 5x multiplier to this transaction cannot be overstated. The base PTC rate for calendar year 2025, as adjusted for inflation pursuant to IRC § 45(e)(2), is $0.0055 per kilowatt-hour ("kWh"). With the 5x multiplier, the effective PTC rate increases to $0.0275 per kWh. When the energy community bonus credit (discussed in Issue 2 below) is included, the effective rate further increases to $0.03025 per kWh. Failure to satisfy the prevailing wage or apprenticeship requirements would reduce the effective credit rate from $0.03025 per kWh (with multiplier and energy community bonus) to $0.0055 per kWh (base rate only, without the energy community bonus which is also applied as a percentage of the base credit amount), reducing estimated annual PTCs from approximately $25.3 million to approximately $4.6 million — an approximately 82% reduction in annual credit value. This would fundamentally undermine the economics of the proposed transfer and would almost certainly cause Pinnacle to withdraw from the transaction.
The following sub-issues have been identified and require resolution:
(a) Prevailing Wage Documentation. We must obtain and review documentation demonstrating prevailing wage compliance for all construction-period contractors and subcontractors. Construction of the Project commenced on April 6, 2023, and the Project achieved commercial operation on November 14, 2025 (the "COD" or "Placed-in-Service Date"). The prevailing wage requirements apply to laborers and mechanics employed by contractors and subcontractors in the construction of the facility and require payment of wages at rates not less than the prevailing rates determined by the Secretary of Labor in accordance with subchapter IV of chapter 31 of title 40, United States Code (the Davis-Bacon Act). Documentation should include certified payroll records, contractor certifications, and any applicable Department of Labor wage determinations for Custer County, Montana.
(b) Apprenticeship Hour Requirements and Ratios. We must confirm compliance with the apprenticeship requirements under IRC § 45(b)(8), which require that a specified percentage of total labor hours on the project be performed by qualified apprentices. The applicable percentage varies depending on the date construction commenced; for projects beginning construction after January 1, 2023, the requirement is that not less than 15% of total labor hours be performed by qualified apprentices. Documentation should include apprenticeship program registrations, apprentice hour logs, and evidence of good-faith efforts to comply if any exemptions from the apprenticeship requirements are claimed.
(c) Cure or Correction Payments. We must assess whether any cure or correction payments under IRC § 45(b)(7)(B) are applicable. Under this provision, a taxpayer that fails to satisfy the prevailing wage requirements may nevertheless be treated as satisfying them if the taxpayer makes correction payments to affected workers (equal to the difference between the wages paid and the prevailing wage, plus interest) and pays a penalty to the IRS. We should determine whether any such payments have been made or are anticipated and, if so, review the documentation supporting the cure.
(d) Grayson Birch PTC Eligibility Memorandum. We must determine whether Grayson Birch & Co. LLP ("Grayson Birch"), the Client's independent tax advisor, has completed or is in the process of preparing a prevailing wage and apprenticeship compliance memorandum as part of their broader PTC eligibility analysis. Howard Ellison, Lead Partner, National Tax — Renewable Energy, at Grayson Birch, is the primary contact. If such a memorandum exists in draft or final form, we should obtain a copy promptly and review it to identify any areas of concern or gaps in the analysis.
(e) Buyer Diligence Expectations. Given Pinnacle Atlantic Partners LP's substantial experience in the IRC § 6418 credit purchase market (approximately $1.2 billion in prior transactions), we should anticipate that Pinnacle and its counsel, HL&S, will require robust documentary evidence of prevailing wage and apprenticeship compliance. This is likely to be a focal point of buyer diligence, and any deficiencies or gaps in the compliance file will be identified and raised during the negotiation process. We should work with the Client to assemble a comprehensive compliance file in advance of buyer diligence requests to avoid delays and to strengthen the Client's negotiating position.
(f) Internal Client Records. We must identify the individual or individuals within the DEH/DRI organization who maintained wage and apprenticeship records during the construction period. Based on preliminary information from the Client, Angela Whitfield, Vice President, Renewables Development, at DRI, was responsible for coordinating compliance, in conjunction with the engineering, procurement, and construction ("EPC") contractor. We should request that Ms. Whitfield compile and produce all relevant records, including any correspondence with the EPC contractor regarding prevailing wage and apprenticeship matters.
Status: Open — awaiting records from client and coordination with Grayson Birch. This is a high-priority issue that should be addressed at the earliest opportunity. The strength of the compliance record will directly affect the scope and cost of the seller's indemnification obligations under the Transfer Agreement (see Issue 4 below) and the availability and pricing of recapture insurance (see Issue 5 below).
Issue 2: Energy Community Certification for Custer County, Montana
The effective PTC rate for the Ridgeway Wind Project includes a 10% energy community bonus credit under IRC § 45(b)(11)(B), which increases the applicable credit amount by 10 percentage points (applied to the base credit amount after application of the 5x multiplier). With the 5x multiplier, the base credit rate is $0.0275 per kWh; the energy community bonus increases this to $0.03025 per kWh (calculated as $0.0275 × 1.10 = $0.03025). The energy community bonus credit adds approximately $2.3 million per year to the estimated annual PTC amount, or approximately $23 million over the 10-year PTC eligibility period.
The Project is located in Custer County, Montana, which has been identified as qualifying as an energy community based on its historical fossil fuel employment characteristics. The specific basis for this qualification must be confirmed, as the energy community designation under IRC § 45(b)(11)(B) can arise from any of three categories:
(i) A brownfield site (as defined in certain subparagraphs of Section 101 of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980);
(ii) A metropolitan statistical area or non-metropolitan statistical area that has (or, at any time during the period beginning after December 31, 2009, had) 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 has an unemployment rate at or above the national average for the prior year; or
(iii) A census tract (or directly adjoining census tract) in which, after December 31, 1999, a coal mine closed or a coal-fired electric generating unit was retired.
The following sub-issues have been identified:
(a) Statutory and Regulatory Basis for Qualification. We must confirm the specific statutory and regulatory basis under which Custer County, Montana, qualifies as an energy community. Based on preliminary research, Custer County appears to qualify under category (ii) above as a non-metropolitan statistical area with significant fossil fuel employment. However, this should be verified against the IRS published guidance and any lists of qualifying energy communities issued by the Department of Energy or the IRS. The Project site encompasses approximately 28,000 acres located approximately 14 miles northeast of Miles City, Custer County, Montana. We must confirm that the Project site falls within a qualifying census tract or statistical area.
(b) IRS Guidance and Published Lists. The IRS and the Department of Energy have published lists and interactive maps identifying qualifying energy communities. We should review the most current published lists and any applicable IRS notices or revenue procedures to confirm Custer County's status. We should also review any applicable Treasury regulations or proposed regulations addressing the energy community bonus credit.
(c) Duration and Stability of Energy Community Designation. A critical question is whether the energy community designation is based on data that could change during the 10-year PTC eligibility period (TY2025 through TY2034) and, if so, whether the designation is "locked in" at the placed-in-service date. If the designation is based on annual employment or unemployment data, there is a risk that Custer County could lose its energy community status during the PTC eligibility period if fossil fuel employment declines below the threshold or if the unemployment rate drops below the national average. Under current IRS guidance, the energy community determination is generally made based on the year in which a facility is placed in service, but this should be confirmed and closely monitored for any changes in regulatory interpretation.
(d) Grayson Birch Analysis. We should determine whether Grayson Birch has addressed the energy community bonus in their PTC eligibility memorandum and, if so, review their analysis. If Grayson Birch has not yet addressed this issue, we should request that they include it in their work product.
(e) Buyer Representations and Warranties. We should consider what representations and warranties the buyer may require in the Transfer Agreement regarding the Project's continued energy community qualification. If there is a risk that the energy community designation could be lost during the PTC eligibility period, the buyer may seek specific indemnification for any reduction in credit amounts resulting from the loss of the energy community bonus.
Status: Open — coordinating with Grayson Birch; awaiting their PTC eligibility memorandum. This is a high-priority issue given the material impact of the energy community bonus on the annual PTC amount and the transfer consideration.
Issue 2A: Ongoing PTC Eligibility — Placed-in-Service and Continuous Operations
In addition to the prevailing wage/apprenticeship and energy community issues addressed above, the ongoing eligibility of the Project for PTCs depends on several fundamental requirements that must be confirmed and monitored throughout the 10-year PTC eligibility period.
(a) Placed-in-Service Date. We must confirm that the Ridgeway Wind Project was placed in service on November 14, 2025, consistent with the COD date. The placed-in-service determination is a factual determination based on when the facility was in a condition or state of readiness and availability for its specifically assigned function — in this case, the production and sale of electricity from wind. The COD certification from Meridian Technical Advisors LLC ("Meridian"), prepared by Dr. Paul Marlowe Commerce Bank, PE, is the primary evidentiary support for this date. We have requested a copy of the COD certification from the Client and should review it upon receipt to confirm that it supports the November 14, 2025, placed-in-service date.
(b) Facility Configuration. The Project consists of 83 wind turbines at 3.0 MW each (249 MW aggregate nameplate capacity) plus one additional 1.0 MW unit serving as a substation backup, for a total nameplate capacity of 250 MW. We should confirm that this configuration is reflected in the COD certification and in the Project's IRS registration (see Issue 8 below).
(c) Sale of Electricity to a Third Party. PTCs under IRC § 45 require that the electricity generated by the qualifying facility be sold to an unrelated person during the taxable year. The Project sells electricity to Great Plains Municipal Power Authority ("GPMPA") under a 20-year power purchase agreement ("PPA") executed on June 12, 2023, at a contract price of $38.50 per MWh. We should confirm that GPMPA is unrelated to the Client and that the PPA remains in full force and effect. We should also obtain a copy of the PPA for review, as the terms of the PPA may be relevant to buyer diligence and to the calculation of the annual true-up (see Issue 7 below).
(d) PTC Eligibility Period. The PTC eligibility period runs for 10 taxable years beginning with the taxable year in which the facility is placed in service. For the Ridgeway Wind Project, this means the eligibility period runs from TY2025 through TY2034. We should confirm this calculation with Grayson Birch and ensure that the Transfer Agreement contemplates the correct eligibility period.
(e) Risks to Continued PTC Generation. We should consider potential risks to the Project's continued ability to generate PTCs during the 10-year eligibility period. These risks include, but are not limited to, extended outages (due to equipment failure, extreme weather events, or force majeure), curtailment by the grid operator (MISO), changes in the Project's ownership structure that could trigger recapture, decommissioning, or abandonment of the facility. The Transfer Agreement should address the allocation of these risks between the seller and the buyer, and the buyer's diligence process will likely focus on the reliability and operational history of the Project.
Status: Open — COD certification requested from client. This is a medium-priority issue that is necessary to support the fundamental PTC eligibility analysis.
II. Lender Consent and Financing Considerations
Issue 3: Redstone Capital Bank Lender Consent Under Section 7.14 of the Credit Agreement
The Ridgeway Wind Project is financed under a Credit Agreement dated March 28, 2023 (the "Credit Agreement"), between Ridgeway Wind Energy LLC, as borrower, and Redstone Capital Bank, N.A. (OCC Charter No. 18742), as administrative agent and lender ("Redstone" or "Redstone Capital Bank"). The Credit Agreement governs a $288.4 million construction-to-term loan facility representing approximately 70% of the total Project cost (loan-to-cost ratio). As of March 1, 2026, the outstanding principal balance under the Credit Agreement is approximately $271.6 million.
Section 7.14 of the Credit Agreement (which has been referenced in the Client's preliminary disclosures but not yet reviewed in full) requires prior written consent of Redstone Capital Bank for any "transfer, sale, or assignment of tax attributes" generated by the Project. The proposed IRC § 6418 transfer of PTCs to Pinnacle Atlantic Partners LP almost certainly constitutes a "transfer, sale, or assignment of tax attributes" within the meaning of this provision, but the precise scope of the defined terms must be analyzed upon receipt and review of the Credit Agreement.
The following sub-issues have been identified and require prompt attention:
(a) Interpretation of Section 7.14. We must obtain the Credit Agreement and review Section 7.14 in its entirety, along with all related defined terms. Key questions include: (i) whether "tax attributes" is defined and, if so, whether the definition encompasses PTCs or only certain enumerated tax attributes; (ii) whether the prohibition applies to a "transfer election" under IRC § 6418 or only to a traditional sale or assignment of credits; and (iii) whether the consent requirement is subject to any reasonableness standard (i.e., "consent not to be unreasonably withheld, conditioned, or delayed") or whether the lender has absolute discretion.
(b) Lender Consent Request. Assuming that lender consent is required (which we believe is the most probable outcome), we should prepare or coordinate the preparation of a formal lender consent request to Redstone Capital Bank. The consent request should describe the proposed transaction in sufficient detail to enable Redstone to evaluate the request, including the identity of the buyer, the economic terms, and the expected impact on the Project's cash flows and debt service coverage. We should anticipate that Redstone will impose conditions on its consent, which may include one or more of the following: (i) a lien on the transfer consideration or assignment of the Transfer Agreement as additional collateral; (ii) a requirement that transfer consideration be deposited into the project accounts governed by the Depositary Agreement; (iii) confirmation that the PTC transfer does not constitute a default or event of default under the Credit Agreement; and (iv) approval of the form and substance of the Transfer Agreement.
(c) Depositary Agreement. We must also obtain and review the Depositary Agreement dated March 28, 2023, between Ridgeway Wind Energy LLC and Redstone Capital Bank, which governs the cash management and revenue waterfall for the Project (see Issue 3A below for detailed analysis). The Depositary Agreement and the Credit Agreement are interrelated documents and must be analyzed together to understand the full scope of the lender consent issues.
(d) Treatment of Transfer Consideration in Project Cash Flows. A critical economic question is whether the transfer consideration received by Ridgeway Wind from Pinnacle (estimated at $23.3 million for Year 1 and approximately $232.76 million over 10 years) will be treated as "project revenue" or "receipts" subject to the revenue waterfall provisions of the Depositary Agreement. If the transfer consideration is swept into the revenue waterfall, it may be applied first to operating expenses, debt service reserve replenishment, and scheduled debt service payments, potentially reducing the net benefit of the transaction to DEH and DRI. We should explore whether a carve-out, side letter, or amendment to the Depositary Agreement can be negotiated with Redstone to permit the transfer consideration to flow to a designated account outside the waterfall.
(e) Timing. Lender consent is likely to be a condition precedent to closing the Transfer Agreement with Pinnacle. Based on our experience with similar project finance consent requests, the lender consent process may take 4 to 8 weeks from the date of initial request to the date of final execution. Accordingly, we recommend engaging with Redstone at the earliest opportunity. The Credit Agreement is governed by New York law, and any amendments or consent letters will need to be consistent with the governing law provisions.
(f) Amendment or Consent Fees. We should inquire whether Redstone will require an amendment fee or consent fee in connection with its approval of the PTC transfer. Such fees are customary in project finance transactions and may range from 10 to 25 basis points of the outstanding loan balance. Based on the current outstanding principal of $271.6 million, this could represent a fee of $271,600 to $679,000. The Client should be made aware of this potential cost.
(g) Relationship Considerations. The Client has advised that DEH has an ongoing relationship with Redstone Capital Bank across multiple project financings. Any consent request should be handled diplomatically to avoid disrupting this relationship. We should coordinate with the Client's relationship team (Marcus Petrov and Fiona Kessler, General Counsel, DEH) to determine the appropriate approach and point of contact at Redstone.
Status: Open — high priority. Copies of the Credit Agreement and Depositary Agreement were included in the document request sent on March 10, 2026. We recommend elevating this issue for immediate attention and scheduling a call with the Client to discuss the lender consent strategy.
Issue 3A: Depositary Agreement Waterfall — Application of Transfer Proceeds
The Depositary Agreement dated March 28, 2023, between Ridgeway Wind Energy LLC and Redstone Capital Bank likely establishes a multi-tiered waterfall for the allocation and disbursement of project revenue among various designated accounts. While we have not yet received the Depositary Agreement, standard project finance depositary agreements in the wind energy sector typically include the following accounts and priority of payments:
(i) Revenue Account (receipt of all project revenues);
(ii) Operating and Maintenance Reserve Account;
(iii) Debt Service Reserve Account;
(iv) Scheduled Debt Service Account (principal and interest);
(v) Major Maintenance Reserve Account;
(vi) Distribution Account (distributions to equity holders, subject to distribution conditions).
The central question for purposes of this transaction is whether the transfer consideration received from Pinnacle under the IRC § 6418 transfer is captured by the waterfall's definition of "revenues" or "receipts." If the Depositary Agreement was drafted before the enactment of IRC § 6418 (which was enacted as part of the Inflation Reduction Act of 2022, signed into law on August 16, 2022, and became effective for taxable years beginning after December 31, 2022), it is possible that the drafters did not contemplate PTC transfer consideration as a category of project revenue. However, if the definitions are drafted broadly — for example, to include "all amounts received by [Ridgeway Wind] from any source" — the transfer consideration could be swept into the waterfall.
The following sub-issues require analysis:
(a) Review the Depositary Agreement to determine whether "revenues," "receipts," or other defined terms are broad enough to encompass IRC § 6418 transfer consideration.
(b) If the transfer consideration is captured by the waterfall, assess the impact on the net proceeds available to DEH. Specifically, calculate the portion of transfer consideration that would be applied to debt service and other senior obligations before any amounts flow to the Distribution Account.
(c) Evaluate the feasibility of negotiating a carve-out or side letter with Redstone to exclude PTC transfer consideration from the waterfall or to create a parallel payment channel for such consideration.
(d) Consider whether Pinnacle will require assurance that Ridgeway Wind can direct transfer proceeds to a designated account. Pinnacle may be concerned about the creditworthiness of the payment obligation if the transfer consideration is subject to the revenue waterfall and senior claims. Conversely, Pinnacle may view the revenue waterfall as protective of the Project's financial stability and therefore supportive of the seller's ongoing ability to operate the Project and generate PTCs.
(e) Coordinate with the Client's finance team to understand the current cash flow projections for the Project and the impact of the transfer consideration on debt service coverage ratios and distribution conditions.
Status: Open — awaiting document production. This issue is closely related to Issue 3 and should be analyzed concurrently with the lender consent issue.
III. Transfer Agreement Terms and Commercial Structure
Issue 4: Scope and Limits of Seller Indemnification Obligations
The indicative term sheet provided by Pinnacle Atlantic Partners LP contemplates broad seller indemnification for credit disallowance, recapture, and reduction events. Indemnification is a core commercial term of any IRC § 6418 credit transfer agreement and is typically the most heavily negotiated provision. The scope of the seller's indemnification obligations will directly affect the Client's residual risk exposure and the economic value of the transaction.
The following sub-issues must be addressed during the negotiation of the Transfer Agreement:
(a) Scope of Representations and Warranties. We must determine the appropriate scope of seller representations and warranties regarding the PTCs and the Project. At a minimum, the buyer will expect representations regarding: (i) PTC eligibility under IRC § 45, including the placed-in-service date, the qualified facility status, and the sale of electricity to an unrelated person; (ii) prevailing wage and apprenticeship compliance sufficient to support the 5x bonus credit multiplier; (iii) energy community qualification sufficient to support the 10% energy community bonus credit; (iv) accuracy of the estimated credit amount; (v) compliance with all applicable IRS registration and procedural requirements; and (vi) ongoing operations and maintenance of the Project in a manner that preserves PTC eligibility. The Client's ability to make each of these representations with confidence will depend on the resolution of the diligence issues identified in Part I above.
(b) Indemnification Caps. We must negotiate reasonable caps on the seller's indemnification obligations. Potential cap structures include:
(1) A dollar cap equal to the transfer consideration received for the applicable taxable year (i.e., the seller indemnifies up to, but not in excess of, the amount it received for the credits that were disallowed or recaptured);
(2) A dollar cap equal to a percentage of the total transfer consideration received across all taxable years (e.g., 100% of consideration received, or a lower percentage such as 75% or 50%);
(3) Time limitations on the survival of representations and indemnification obligations, ideally aligned with the applicable statute of limitations for IRS assessment of the credits (generally three years from the due date of the transferee's tax return, or six years in certain circumstances);
(4) Basket and deductible mechanics (e.g., a de minimis threshold below which no indemnification is owed, with or without a tipping basket).
(c) Allocation of Risk Categories. A fundamental structuring question is the allocation of risk between seller-specific risks and market or regulatory risks. We recommend advocating for a clear distinction between:
(1) Credit disallowance events caused by the seller's breach of representations or warranties regarding PTC eligibility, prevailing wage compliance, energy community qualification, or other seller-specific matters — these risks are appropriately borne by the seller;
(2) Changes in law, changes in IRS interpretation of IRC § 6418, or IRS challenges to the transferability mechanism itself — these are market or regulatory risks that are not properly borne by the seller and should be excluded from the indemnification obligations;
(3) Buyer-side filing errors, buyer's failure to properly report the transferred credits, or IRS challenges to the buyer's eligibility or tax position — these are buyer risks that should be excluded from seller indemnification.
(d) Definitions. We should define "disallowance events" narrowly and with precision. The definition should exclude general changes in law, buyer-side filing errors, and IRS challenges to the buyer's eligibility or tax position. We should also define "recapture events" by reference to the specific recapture provisions of IRC § 45, including changes in ownership, cessation of operations, and other specified events.
(e) Knowledge Qualifiers and Materiality. We should consider whether representations are appropriately qualified by knowledge and materiality standards. For example, representations regarding prevailing wage compliance might be qualified to the "actual knowledge" of specified individuals (e.g., Angela Whitfield), or might require a broader "constructive knowledge" or "should have known" standard. Pinnacle and HL&S will likely resist broad knowledge qualifiers, particularly for representations that go to the fundamental eligibility of the credits.
(f) Guarantor Support. We must assess whether the indemnification obligations should be limited to the Ridgeway Wind entity level or whether Pinnacle will require a parent guaranty from Dunmore Renewables Inc. or Dunmore Energy Holdings Ltd. Given that Ridgeway Wind is a special-purpose project company with limited assets beyond the Project itself, it is likely that Pinnacle will require some form of credit support from a parent entity. The Client should be prepared for this request and should evaluate the implications of providing a parent guaranty, including any restrictions under the Credit Agreement on the incurrence of additional obligations by DRI or DEH.
(g) Buyer's Negotiating Posture. Pinnacle's prior experience with approximately $1.2 billion in IRC § 6418 credit purchases means that its form of indemnity provisions is likely well-developed and has been tested across multiple transactions. We should anticipate that HL&S, on behalf of Pinnacle, will take firm positions on indemnification scope and resist significant deviations from their standard form. Nathaniel Strauss, in particular, has a reputation as an aggressive but commercially sophisticated negotiator in this space. We should prepare our negotiating positions carefully and be prepared to offer justifications for any deviations from market terms.
Status: Open — pending receipt of Pinnacle's preferred form Transfer Agreement and further negotiation. This is a high-priority issue that will require significant attention during the documentation phase.
Issue 5: Recapture Insurance from Northfield Specialty Insurance Co.
Corbin Hale & Associates Inc. ("Corbin Hale"), with Steven Rask serving as lead broker, is advising DEH on tax credit recapture insurance and transfer indemnity insurance coverage for this transaction. The prospective insurer is Northfield Specialty Insurance Co. ("Northfield"), located at 80 Pine Street, New York, NY 10005. Tax credit insurance has become an increasingly important feature of IRC § 6418 credit transfer transactions, and both sellers and buyers have come to view insurance as a valuable risk-mitigation tool that can facilitate agreement on indemnification and holdback terms.
The following sub-issues have been identified:
(a) Insurance Structure and Named Insured. We must determine whether the recapture insurance is intended to backstop the seller's indemnification obligations to the buyer (i.e., Ridgeway Wind or DRI purchases the policy to cover its own indemnity exposure) or whether the buyer, Pinnacle, will be a named insured or additional insured under the policy. The structure of the policy will affect the claims process, the assignment of policy proceeds, and the interplay between the insurance and the holdback escrow.
(b) Scope of Insured Events. The scope of coverage under the insurance policy must be carefully defined. Key questions include: (i) whether the policy covers only recapture events under IRC § 45 (e.g., change in ownership, cessation of operations) or also broader credit disallowance events (e.g., failure to satisfy prevailing wage or apprenticeship requirements, disqualification of energy community status, IRS challenge to the placed-in-service date); (ii) whether the policy covers changes in law that retroactively affect credit eligibility; and (iii) whether the policy covers buyer-side filing errors or only seller-side compliance failures. Ideally, the insurance coverage should be coextensive with the seller's indemnification obligations under the Transfer Agreement, so that the insurance provides full protection for the seller's exposure.
(c) Policy Limits and Duration. The policy limits should correspond to the indemnification cap under the Transfer Agreement. Given the estimated 10-year aggregate transfer consideration of approximately $232.76 million (or approximately $253 million in total credit value), the insurance coverage would need to be substantial. We should determine whether Northfield is prepared to offer a multi-year policy covering the full 10-year PTC eligibility period or whether annual renewal will be required. A multi-year policy would provide greater certainty but may be more expensive and may require periodic underwriting reviews.
(d) Premium Costs. Insurance premiums for tax credit recapture and transfer indemnity policies are a significant cost that must be factored into the overall transaction economics. Based on market information, premiums for tax credit insurance currently range from approximately 2% to 5% of the face amount of coverage, depending on the nature and perceived risk of the underlying credits. We should determine whether the premium cost will be borne entirely by the seller (as a cost of doing business and providing indemnification) or will be shared with the buyer as a negotiated economic term. Premium sharing is sometimes used as a means of reducing the seller's cost while providing the buyer with comfort regarding the quality of the insurance coverage.
(e) Underwriting Requirements. Northfield's underwriting process will likely require access to detailed diligence materials, including the Grayson Birch PTC eligibility memorandum, the Meridian energy production estimate, documentation of prevailing wage and apprenticeship compliance, and the Transfer Agreement. We should coordinate with Steven Rask at Corbin Hale to understand Northfield's underwriting timeline and requirements, and we should ensure that the necessary diligence materials are available to support the underwriting process.
(f) Buyer Review of Policy. We should consider whether Pinnacle will insist on reviewing and approving the form and substance of the insurance policy before closing the Transfer Agreement. If Pinnacle is a named insured or additional insured, it will almost certainly require approval rights. Even if the policy is solely a seller-side arrangement, Pinnacle may wish to review the policy to confirm that the coverage is adequate to support the seller's indemnification obligations and to reduce the risk of holdback claims.
(g) Coordination with Corbin Hale. We should coordinate with Steven Rask at Corbin Hale to obtain preliminary indications from Northfield regarding coverage terms, premium costs, and underwriting timeline. An introductory call between Calderwood & Harkness, Corbin Hale, and Northfield may be warranted.
Status: Open — awaiting preliminary insurance term sheet from Corbin Hale/Northfield. This is a medium-priority issue that may become higher priority as the indemnification and holdback negotiations progress.
Issue 6: Escrow Mechanics with Commonwealth Fiduciary Trust Company
The indicative term sheet from Pinnacle contemplates a 15% indemnity holdback from each annual transfer payment, to be held in escrow by a mutually agreed-upon escrow agent. The prospective escrow agent is Commonwealth Fiduciary Trust Company ("Commonwealth Fiduciary"), located at One Liberty Place, 1650 Market Street, Suite 3600, Philadelphia, PA 19103.
Based on the estimated Year 1 transfer consideration of $23,271,803, the Year 1 holdback amount would be $3,490,770 (calculated as $23,271,803 × 15%). The holdback release period under the indicative term sheet is 36 months from the date of each escrow deposit, subject to confirmation that no disallowance event has occurred.
The following sub-issues require attention:
(a) Escrow Agreement Terms. The escrow agreement must address the following key terms: (i) the identity and duties of the escrow agent (Commonwealth Fiduciary is the prospective agent, but has not yet been formally engaged); (ii) the investment parameters for escrowed funds (e.g., short-term U.S. Treasury obligations, money market funds, FDIC-insured deposits); (iii) the allocation of investment income (whether interest accrues to the benefit of the seller, the buyer, or is shared); (iv) the conditions for release of escrowed funds (passage of time only, or affirmative confirmation that no disallowance event has occurred and no claims are pending); (v) the mechanics for claims against the escrow (notice requirements, dispute resolution, and timing); and (vi) the procedures for early release or partial release of escrowed funds.
(b) Holdback Percentage. The 15% holdback proposed in the indicative term sheet should be evaluated against market practice for IRC § 6418 credit transfer transactions. Based on our experience and market surveys, holdback percentages in the current market range from 10% to 20%, with 15% being within the range but on the higher end for credits supported by robust compliance documentation and recapture insurance. We should consider whether a lower holdback percentage (e.g., 10%) can be negotiated, particularly if recapture insurance from Northfield is in place and provides additional protection to the buyer. The holdback percentage and the availability of insurance are typically negotiated in tandem, with the buyer's overall risk comfort being the determinative factor.
(c) Cumulative Escrow Exposure. The 36-month holdback release period creates the potential for multiple years' holdbacks to be outstanding simultaneously. For example, at month 24 of the transaction, the Year 1 and Year 2 holdbacks would both be outstanding, totaling approximately $7 million (assuming comparable annual credit amounts). At month 36, the Year 1 holdback would be released (assuming no claims), but the Year 2 and Year 3 holdbacks would remain outstanding. This cumulative exposure should be modeled and presented to the Client, and the Client should be made aware of the cash flow implications.
(d) Exclusivity of Remedy. A critical negotiation point is whether the holdback amount is the exclusive remedy for the buyer in the event of a credit disallowance or recapture, or whether the buyer retains direct indemnification claims against the seller and/or guarantor in excess of the holdback amount. From the seller's perspective, the holdback should ideally be the exclusive remedy (or at least the first source of recovery), with direct indemnification claims available only after the holdback is exhausted. From the buyer's perspective, the holdback may be viewed as a minimum level of protection, with the buyer retaining full indemnification rights regardless of the holdback.
(e) Escrow Agent Selection and Fees. Commonwealth Fiduciary Trust Company has been identified as the prospective escrow agent, but has not yet been formally engaged. Commonwealth Fiduciary will have its own form of escrow agreement, which will need to be reviewed and adapted to the specific needs of this transaction. Escrow agent fees are typically modest (e.g., $5,000 to $15,000 per year for a straightforward escrow), and the question of whether fees are borne by the seller, the buyer, or split between them should be addressed in the Transfer Agreement.
(f) Coordination with Insurance. The escrow mechanics and the recapture insurance from Northfield (Issue 5) should be coordinated to avoid duplication and to optimize the overall risk allocation structure. For example, if the insurance policy provides first-dollar coverage for credit disallowance events, the holdback escrow may serve primarily as a backstop for events not covered by insurance (e.g., breaches of non-insurance-related representations), and a lower holdback percentage may be appropriate.
Status: Open — escrow agent not yet formally engaged. This is a medium-priority issue that will be addressed during the documentation and negotiation phase.
Issue 7: Annual True-Up and Payment Timing
The indicative term sheet provides for a lump-sum payment of each taxable year's estimated credits, payable within 30 days after the later of (a) the filing of Ridgeway Wind's IRS pre-filing registration for the applicable taxable year and (b) the annual true-up date. The payment mechanics are a critical commercial term that will affect the timing and predictability of cash flows for both the seller and the buyer.
The following sub-issues have been identified:
(a) Definition of "Annual True-Up Date." The term "annual true-up date" is not defined in the indicative term sheet, and its meaning must be clarified during negotiation. Options include: (i) a fixed calendar date (e.g., March 31 of the year following the credit year), which provides certainty but may not align with the availability of actual generation data; (ii) a date tied to the finalization of actual generation data for the credit year (e.g., 60 or 90 days after the end of the calendar year, when metered generation data has been verified); or (iii) a date tied to the filing of the transferor's tax return for the credit year.
(b) Estimated vs. Actual Credits. The estimated annual PTC of $25,295,655 is based on a P50 generation estimate of 836,220,000 kWh, derived from the Project's 250 MW nameplate capacity, 8,760 annual hours, and a 38.2% P50 net capacity factor as estimated by Meridian Technical Advisors LLC. Actual generation will vary year-to-year due to wind resource variability, turbine availability, curtailment by the grid operator, and other factors. We must determine whether the annual transfer payment is based on estimated credits (calculated using the P50 generation estimate or another methodology) with a post-year true-up based on actual generation, or whether the payment is based solely on actual credits determined after the close of each taxable year.
(c) True-Up Mechanics. If the payment is based on estimated credits with a true-up, the Transfer Agreement must establish: (i) the methodology for calculating the estimated credit amount (e.g., based on Meridian's P50 energy production estimate, with or without adjustments for historical actual generation); (ii) the methodology for calculating actual credits (based on metered generation data); and (iii) the reconciliation mechanics, including whether overpayments are refunded by the seller and underpayments are supplemented by the buyer, and the timing and method of reconciliation payments.
(d) PTC Rate Inflation Adjustments. The effective PTC rate of $0.03025 per kWh applies to TY2025 and is based on the inflation-adjusted base rate for that year. For subsequent taxable years (TY2026 through TY2034), the PTC rate will be adjusted for inflation pursuant to IRC § 45(e)(2). The annual payment calculation under the Transfer Agreement must account for these inflation adjustments. We should determine whether the transfer price (i.e., the per-dollar discount rate applied to the face value of the credits) is fixed for the life of the agreement or is subject to adjustment.
(e) Generation Data Source and Verification. We should determine the source and verification methodology for actual generation data. Potential sources include: (i) the Project's supervisory control and data acquisition ("SCADA") system; (ii) MISO settlement data (the Project is located in the MISO service territory); and (iii) invoicing records under the PPA with Great Plains Municipal Power Authority. The Transfer Agreement should specify the authoritative source of generation data and establish a process for resolving any discrepancies.
(f) Sensitivity Analysis. The actual generation in any given year may materially exceed or fall below the P50 estimate. The PTC Credit Calculation Model (referenced in the structuring memorandum under separate cover) includes a sensitivity range analysis showing the impact of P75, P50, and P25 generation scenarios on annual PTC amounts and transfer consideration. We should ensure that the Transfer Agreement and escrow mechanics are designed to accommodate generation variability.
(g) Payment Mechanics. Transfer consideration will be remitted by wire transfer to Ridgeway Wind's designated account. However, the designated account may need to comply with the Depositary Agreement waterfall provisions (see Issue 3A above). This creates a potential conflict: if the designated account is a project account subject to the waterfall, the transfer consideration may be applied to senior obligations before reaching DEH. If the designated account is outside the waterfall, lender consent and/or an amendment to the Depositary Agreement may be required.
Status: Open — requires negotiation with Pinnacle/HL&S. This is a medium-priority issue that will be addressed during the documentation phase.
IV. IRS Registration and Procedural Requirements
Issue 8: Interaction of IRS Registration Process with Transfer Closing Timeline
Under Treasury Regulations § 1.6418-4, the transferor must complete a pre-filing registration on the IRS Energy Credits Online ("ECO") portal for each taxable year for which a transfer election is made under IRC § 6418. The pre-filing registration process is a mandatory prerequisite to the transfer election; without a valid registration number, the transfer election cannot be made, and the transferred credits cannot be claimed by the transferee on its federal income tax return. The registration number must be obtained before the transferor's tax return filing deadline for the relevant taxable year and must be included on both the transferor's and transferee's federal income tax returns.
The current status of the IRS Energy Credits Online registration for TY2025 is pending. Registration has not yet been filed.
The following sub-issues require resolution:
(a) Registration Timeline. We must determine the timeline for completing the IRS pre-filing registration for TY2025. The registration must be completed before the filing deadline of the transferor's federal income tax return for TY2025. Dunmore Renewables Inc. (as the tax owner of the disregarded Ridgeway Wind LLC) files a calendar-year federal corporate income tax return, with a regular filing deadline of April 15, 2027 (for TY2026), but for TY2025 the deadline would be April 15, 2026, unless an extension is filed. If a six-month extension is elected, the extended deadline would be October 15, 2026. We should confirm the applicable filing deadline and work backward to establish a target date for registration completion.
(b) Registrant Identity. Ridgeway Wind Energy LLC is a disregarded entity for federal income tax purposes, with Dunmore Renewables Inc. as its sole member. Under Treas. Reg. § 1.6418-4, the "eligible taxpayer" making the transfer election is the entity that would otherwise be entitled to claim the credit — i.e., the entity that reports the income and expenses of the qualified facility on its federal income tax return. For a disregarded entity, this is the owner (DRI). We must confirm whether the IRS Energy Credits Online registration is filed at the Ridgeway Wind level (as the facility owner) or the DRI level (as the taxpayer). Current IRS guidance suggests that the registration is made by the eligible taxpayer (DRI), but we should verify this with Grayson Birch, which may have more current guidance from its engagement with the IRS ECO portal.
(c) Required Registration Information. The pre-filing registration requires submission of detailed information, including but not limited to: project details (nameplate capacity, COD date, location), credit type (IRC § 45 PTC), estimated credit amount for the taxable year, transferee identity (Pinnacle Atlantic Partners LP), the transferee's employer identification number ("EIN"), the transfer consideration, and other data elements specified in the applicable IRS forms and instructions. We should compile this information in advance and coordinate with both the Client and Grayson Birch to ensure accuracy and completeness.
(d) Registration as a Condition Precedent. The registration process may create a de facto condition precedent to closing the Transfer Agreement. If the Transfer Agreement requires that a valid registration number be obtained before the buyer is obligated to make payment, any delays in the IRS ECO portal — whether due to IRS processing times, system outages, or errors in the registration submission — could delay receipt of transfer consideration. We should consider whether the Transfer Agreement should include a mechanism for addressing registration delays, such as a pre-closing registration verification process or a covenant by the seller to complete registration by a specified date.
(e) Coordination with Grayson Birch. Grayson Birch (Howard Ellison) is preparing the PTC eligibility memorandum and may be handling the IRS Energy Credits Online registration filing as part of its engagement scope. We should coordinate with Grayson Birch on the registration process, timeline, and any issues encountered during the registration process. If Grayson Birch is not handling the registration filing, we should determine who will be responsible and ensure that the filing is completed on a timely basis.
(f) Buyer Expectations. We should determine whether Pinnacle will require confirmation of a valid registration number as a closing condition under the Transfer Agreement. If so, we should establish a mechanism for providing such confirmation, such as a copy of the IRS registration confirmation or a screenshot of the ECO portal showing the registration number. We should also determine whether Pinnacle will require the registration number to be included in the Transfer Agreement itself or in a closing certificate.
(g) Annual Registration Requirement. For each of TY2025 through TY2034, a new pre-filing registration will be required under Treas. Reg. § 1.6418-4. This creates an annual administrative process that must be built into the ongoing transaction management. The Transfer Agreement should include covenants by the seller to complete the annual registration on a timely basis and to provide the registration number to the buyer promptly upon receipt.
Status: Open — registration not yet filed; timeline to be established. This is a high-priority issue given the potential for registration-related delays to affect the closing timeline and the annual payment process.
Issue 8A: Tax Return Filing Coordination
The transfer election under IRC § 6418 is made on the transferor's federal income tax return for the relevant taxable year. Because Ridgeway Wind Energy LLC is a disregarded entity, the transfer election will be made on the federal income tax return of Dunmore Renewables Inc. (Form 1120) for the applicable taxable year. The transferred credits will then be reported on Pinnacle Atlantic Partners LP's federal income tax return (Form 1065, Schedule K-1, or as otherwise applicable to a limited partnership) with the IRS registration number.
The following coordination steps are necessary:
(a) Coordinate the return filing timeline with Marcus Petrov (Vice President, Tax, DEH) and Grayson Birch, which is expected to prepare or assist in the preparation of DRI's federal income tax return.
(b) Ensure that the Transfer Agreement includes covenants by the seller regarding the timely filing of the transferor's federal income tax return and the making of the IRC § 6418 transfer election on such return. The buyer will need assurance that the election will be properly made and that the registration number will be included on the transferor's return.
(c) Coordinate with Pinnacle/HL&S regarding the information that Pinnacle will need to report the transferred credits on its federal income tax return, including the registration number, the credit amount, the credit type, and any other required data elements.
(d) Establish a process for sharing tax return filing confirmations between the parties, subject to appropriate confidentiality protections. The buyer may require a copy of the relevant portions of the transferor's return (or a certification from the transferor's tax advisor) confirming that the election was properly made.
Status: Open — to be coordinated with Marcus Petrov and Grayson Birch.
V. Entity Structure and Withholding
Issue 9: Cayman-to-U.S. Entity Chain and Withholding Implications
The ownership structure of the Project Company involves a Cayman Islands parent entity (Dunmore Energy Holdings Ltd., CR-284319), which owns a Delaware corporation (Dunmore Renewables Inc., file number 7491826), which in turn is the sole member of a Delaware limited liability company treated as a disregarded entity for federal income tax purposes (Ridgeway Wind Energy LLC, file number 7603517). While both the credit-generating entity and the eligible taxpayer are U.S. entities, the presence of a foreign parent entity in the ownership chain raises questions that must be analyzed and addressed.
The following sub-issues require analysis:
(a) Character of Transfer Consideration. Under current guidance, the amount paid by the transferee to the transferor in an IRC § 6418 credit transfer is not treated as gross income to the transferor, and the amount paid is not deductible by the transferee. This treatment is established by IRC § 6418(b)(1) and (2) and confirmed by Treas. Reg. § 1.6418-2. We must confirm this treatment under the applicable regulations and assess whether any exceptions or anti-abuse rules could alter this characterization.
(b) Withholding Obligations. Even though the transfer consideration is not treated as gross income to the transferor, we must assess whether any portion of the transaction could give rise to withholding obligations under the following provisions:
(i) IRC § 1441 (withholding on nonresident aliens — applicable to payments of U.S.-source fixed or determinable annual or periodical income);
(ii) IRC § 1442 (withholding on foreign corporations — applicable to payments of U.S.-source income to foreign corporations);
(iii) IRC § 1446 (withholding on foreign partners' share of effectively connected income); and
(iv) FIRPTA (IRC §§ 897 and 1445 — withholding on dispositions of U.S. real property interests).
Because the credit-generating entity (Ridgeway Wind) and the eligible taxpayer making the election (DRI) are both U.S. domestic entities, and because the transfer consideration flows from Pinnacle (a U.S. limited partnership) to Ridgeway Wind / DRI (U.S. entities), the Cayman parent should not directly implicate withholding under IRC §§ 1441, 1442, or 1446. However, we should confirm this analysis, particularly in light of any upstream distributions from DRI to DEH that may follow receipt of the transfer consideration. Additionally, we should confirm that the IRC § 6418 transfer does not constitute a disposition of a "United States real property interest" within the meaning of IRC § 897 that would trigger FIRPTA withholding.
(c) Buyer Representations. We should anticipate that Pinnacle or HL&S will require representations regarding the tax status of the entity chain, including: (i) confirmation that Ridgeway Wind is a disregarded entity for federal income tax purposes; (ii) confirmation that DRI is a domestic corporation and the "eligible taxpayer" for purposes of IRC § 6418; (iii) confirmation that DEH's Cayman Islands domicile does not affect credit eligibility, transfer mechanics, or the buyer's ability to claim the transferred credits; and (iv) disclosure of any intercompany arra