PRIVILEGED AND CONFIDENTIAL ATTORNEY WORK PRODUCT ATTORNEY-CLIENT PRIVILEGED COMMUNICATION
CALDERWOOD & HARKNESS LLP 700 Fifth Avenue, 33rd Floor New York, New York 10019 Telephone: (212) 554-7000 Facsimile: (212) 554-7001
MEMORANDUM
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 25, 2026
RE: Review and Commentary on Indicative Term Sheet — Proposed IRC § 6418 Transfer of Production Tax Credits, Ridgeway Wind Project
MATTER NO.: 1016-00008
BILLING CODE: 09417.00001
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I. Executive Summary
Calderwood & Harkness LLP ("C&H" or "we") has reviewed the indicative term sheet (the "Term Sheet") received from Pinnacle Atlantic Partners LP ("Pinnacle" or "Buyer"), dated March 12, 2026, which was delivered to Dunmore Energy Holdings Ltd. ("DEH") by Pinnacle's outside counsel, Hargrove, Liddell & Strauss LLP ("HL&S") (lead partner Nathaniel Strauss; senior associate Catherine Yoon). This memorandum sets forth our detailed analysis and commentary on the Term Sheet and our recommended negotiation positions in anticipation of proceeding toward definitive documentation.
The Term Sheet proposes the purchase by Pinnacle of transferable Production Tax Credits ("PTCs") under Section 6418 of the Internal Revenue Code of 1986, as amended (the "Code" or "IRC"), generated by the 250-megawatt Ridgeway Wind Project (the "Project"), an onshore wind energy generation facility located on approximately 28,000 acres of leased ranchland, 14 miles northeast of Miles City, Custer County, Montana. The Project reached commercial operation on November 14, 2025, and the PTC eligibility period runs from taxable year 2025 through taxable year 2034.
Ridgeway Wind Energy LLC ("RWE"), a Delaware limited liability company and the owner and operator of the Project, would serve as the credit generator and proposed transferor under the transaction. RWE is a wholly owned subsidiary of Dunmore Renewables Inc. ("DRI"), itself a wholly owned subsidiary of DEH, which is organized under the laws of the Cayman Islands.
Overall Assessment. The Term Sheet reflects generally market-standard terms for an IRC § 6418 credit transfer transaction. However, several provisions tilt materially in Buyer's favor, and if left unaddressed, would expose RWE and its parent entities to disproportionate economic and legal risk relative to the nature of the transaction. The most significant areas of concern are: (i) the breadth of the indemnification scope and the absence of any cap on Seller's aggregate indemnification liability; (ii) the overly expansive definition of "Disallowance Event"; (iii) holdback mechanics that are structured at the high end of the market range with interest accruing entirely to Buyer; (iv) certain Seller representations — particularly regarding prevailing wage and apprenticeship compliance and energy community qualification — that are absolute rather than appropriately qualified; and (v) the inclusion of an expansive right of first offer on credits from other DEH affiliate projects. C&H recommends targeted negotiations on approximately eight priority provisions and six additional important or cleanup items before proceeding to definitive documentation.
Based on the estimated annual energy production of 836,220,000 kWh and an effective PTC rate of $0.03025/kWh (inclusive of the 5x bonus credit multiplier and the 10% energy community adder), the estimated 10-year aggregate nominal PTC generation is approximately $253,000,000. At the proposed transfer price of $0.92 per $1.00 of eligible credit, the estimated 10-year aggregate transfer consideration to Seller is approximately $232,760,000.
We elaborate on each of these issues, and our recommended negotiation positions, in the sections that follow.
II. Background and Transaction Overview
A. The Ridgeway Wind Project
The Ridgeway Wind Project is a 250-megawatt onshore wind energy generation facility consisting of 83 wind turbines, each with a rated capacity of 3.0 MW, plus one 1.0 MW substation backup unit, for an aggregate nameplate capacity of 250 MW. The Project is situated on approximately 28,000 acres of leased ranchland located 14 miles northeast of Miles City, Custer County, Montana. The turbines were manufactured by a leading OEM supplier and installed pursuant to a turnkey engineering, procurement, and construction contract that was substantially completed in the fourth quarter of 2025.
The Project's net capacity factor at a P50 confidence level is 38.2%, as determined by Meridian Technical Advisors LLC ("Meridian"), an independent engineering firm (lead engineer Dr. Paul Marlowe Commerce Bank, P.E.), which prepared the energy production estimate and certified the commercial operations date. Based on this capacity factor, the estimated annual electricity generation is approximately 836,220,000 kWh, calculated as follows: 250 MW × 8,760 hours per year × 38.2% net capacity factor.
The total development and construction cost of the Project was approximately $412 million, funded through a combination of $288.4 million in construction-to-term loan financing provided by Redstone Capital Bank, N.A. (OCC Charter No. 18742), and $123.6 million in equity contributed by DRI. As of March 1, 2026, the outstanding principal balance under the Redstone credit facility is $271.6 million. The Project's revenues are supported by a 20-year power purchase agreement (the "PPA") with Great Plains Municipal Power Authority at a fixed price of $38.50/MWh, executed on June 12, 2023. The PPA provides substantial long-term revenue certainty and is a significant contributor to the Project's creditworthiness in the context of this transaction.
With respect to transmission interconnection, the Project holds MISO Queue Position J-1147, and a Generator Interconnection Agreement with NorthStar Transmission Holdings LLC was executed on September 3, 2024. The Project has been fully interconnected and has been delivering energy to the grid since the commercial operations date.
B. PTC Computation
The PTCs generated by the Project are calculated pursuant to IRC § 45(a), as modified by the Inflation Reduction Act of 2022 (Pub. L. No. 117-169). The key computational inputs are as follows:
Base PTC Rate. The base PTC rate for 2025 (as adjusted for inflation pursuant to IRC § 45(e)(2)) is $0.0055 per kilowatt-hour.
5x Bonus Credit Multiplier. The Project satisfies the prevailing wage and apprenticeship requirements set forth in IRC § 45(b)(6) and the related Treasury Regulations. As a result, the Project qualifies for the 5x bonus credit multiplier, which increases the effective PTC rate to $0.0275 per kilowatt-hour ($0.0055 × 5).
Energy Community Bonus. The Project is located in an "energy community" as defined in IRC § 45(b)(11)(B). Custer County, Montana qualifies as a census tract with historical fossil fuel employment exceeding the applicable statutory thresholds. The energy community designation provides an additional 10% adder to the PTC rate, yielding an effective rate of $0.03025 per kilowatt-hour ($0.0275 × 1.10).
Estimated Year 1 PTC. Based on estimated annual generation of 836,220,000 kWh at an effective rate of $0.03025/kWh, the estimated Year 1 PTC is approximately $25,295,655 (approximately $25.3 million).
Estimated 10-Year Aggregate PTC. Over the full 10-year PTC eligibility period (TY2025 through TY2034), the estimated aggregate nominal PTC generation (before inflation adjustments in years 2 through 10) is approximately $253,000,000. Actual aggregate PTCs will be higher to the extent the base rate is adjusted upward for inflation in subsequent years, but the Term Sheet and this memorandum use the nominal figure for purposes of pricing and financial analysis.
C. Proposed Transfer Mechanism
The transaction contemplates a direct transfer election under IRC § 6418 by RWE (as transferor) to Pinnacle (as transferee). Section 6418, enacted as part of the Inflation Reduction Act of 2022, permits eligible taxpayers that generate certain clean energy tax credits — including PTCs under IRC § 45 — to elect to transfer all or a portion of such credits to unrelated eligible transferees in exchange for cash consideration. The transfer election is made on a taxable-year-by-taxable-year basis and requires pre-filing registration through the IRS Energy Credits Online portal in accordance with Treas. Reg. § 1.6418-4.
Pinnacle qualifies as an eligible transferee under IRC § 6418(a) and the applicable Treasury Regulations. Pinnacle is a limited partnership organized under Delaware law with a substantial and consistent federal income tax liability, averaging approximately $480 million per year over the prior three fiscal years. Pinnacle has extensive experience in § 6418 credit transfer transactions, having completed approximately $1.2 billion in cumulative credit purchases across solar, wind, and battery storage projects. This institutional track record is relevant to the negotiation because it reflects Pinnacle's sophistication and its standard playbook for these transactions — terms that deviate from Pinnacle's typical positions may be difficult but not impossible to renegotiate.
The proposed governing law for the transfer agreement is New York law, which is standard for transactions of this type and acceptable from Seller's perspective.
D. Advisors. The following advisors are currently engaged or expected to be engaged in connection with this transaction:
DEH Outside Tax Advisor: Grayson Birch & Co. LLP (lead partner Howard Ellison). Grayson Birch is preparing the PTC eligibility memorandum, the cost segregation analysis for the Project, and will assist with IRS registration under Treas. Reg. § 1.6418-4.
Independent Engineer: Meridian Technical Advisors LLC (Dr. Paul Marlowe Commerce Bank, P.E.). Meridian prepared the energy production estimate supporting the P50 net capacity factor of 38.2% and issued the COD certification for the Project.
Insurance Broker: Corbin Hale & Associates Inc. (Steven Rask, lead broker). Corbin Hale is expected to procure tax credit recapture and transfer indemnity insurance in connection with this transaction.
Prospective Recapture Insurer: Northfield Specialty Insurance Co. (80 Pine Street, New York, NY 10005). Northfield is the anticipated underwriter for recapture insurance coverage.
Prospective Escrow Agent: Commonwealth Fiduciary Trust Company (One Liberty Place, 1650 Market Street, Suite 3600, Philadelphia, PA 19103). Commonwealth is expected to serve as escrow agent for the indemnity holdback deposits.
Pinnacle's Outside Counsel: Hargrove, Liddell & Strauss LLP (Nathaniel Strauss, partner; Catherine Yoon, senior associate).
III. Summary of Key Commercial Terms in the Term Sheet
Set forth below is a detailed summary of the key commercial terms reflected in the Term Sheet, together with our analysis and commentary on each provision.
A. Transfer Price
The Term Sheet proposes a transfer price of $0.92 per $1.00 of eligible PTC transferred (92 cents on the dollar). Based on the estimated annual PTC of $25,295,655, the estimated Year 1 transfer consideration is approximately $23,271,803 (i.e., $25,295,655 × 0.92 ≈ $23,271,803). Over the full 10-year PTC eligibility period, the estimated aggregate nominal transfer consideration is approximately $232,760,000 (i.e., $253,000,000 × 0.92 = $232,760,000).
Commentary. The proposed pricing of $0.92 per dollar of credit falls within the current market range of $0.88 to $0.95 for wind PTCs transferred under IRC § 6418. Based on our review of recent comparable transactions and market intelligence from Corbin Hale & Associates, the median pricing for large-scale onshore wind PTC transfers executed in the fourth quarter of 2025 and first quarter of 2026 has been approximately $0.91 to $0.93, with premium credits — particularly those supported by strong offtake agreements, experienced operators, and low recapture risk — trading at the upper end of that range or above.
Given the Ridgeway Wind Project's credit profile — including a 20-year investment-grade PPA with Great Plains Municipal Power Authority, a well-capitalized sponsor in DEH, full prevailing wage and apprenticeship compliance supporting the 5x multiplier, energy community qualification supporting the 10% adder, and no identified recapture risk as of COD — we believe the Project represents a premium credit profile. Accordingly, while $0.92 is a reasonable starting point for discussions, there may be room to improve the price by one to two cents per dollar, particularly if Seller can secure recapture insurance from Northfield that reduces Buyer's perceived risk. We note, however, that price is generally less negotiable than structural terms in these transactions, and the most impactful improvements to Seller's economic position may come from favorable adjustments to the holdback rate, escrow interest allocation, and indemnification mechanics rather than headline pricing.
B. Payment Timing and Mechanics
The Term Sheet provides for a lump-sum payment for each taxable year's estimated credits, payable within 30 days after the later of: (a) the filing of RWE's IRS pre-filing registration on the IRS Energy Credits Online portal and receipt of a registration number under Treas. Reg. § 1.6418-4; and (b) the annual "true-up date," defined as the date on which actual generation data for the applicable taxable year is available and verified.
Payment is to be made in immediately available funds by wire transfer to an account designated by Seller in a notice delivered no fewer than three business days prior to the applicable payment date.
Commentary. The payment structure is generally consistent with market practice. However, several aspects of the true-up mechanism require further definition. Specifically, the Term Sheet defines the true-up based on "verified actual generation data," but does not specify: (i) the standard of verification (e.g., whether verification requires comparison of SCADA data against revenue-grade meter data, or a more formal independent engineering review); (ii) the identity of the verifier (e.g., whether the independent engineer or a mutually agreed third party performs the verification); or (iii) any deadline by which the true-up must occur. These ambiguities could result in material delays in payment.
C&H recommends that the definitive agreement specify the following:
(a) Verification of annual generation data shall be performed by Meridian Technical Advisors LLC (or such other independent engineer as the parties may mutually agree in writing), based on a review of SCADA data, revenue-grade meter readings, and any curtailment reports from the MISO balancing authority.
(b) The true-up date for each taxable year shall be no later than March 31 of the calendar year following the applicable taxable year (e.g., March 31, 2027 for TY2026).
(c) If the parties disagree on the verified generation data, the dispute shall be submitted to a mutually agreed independent engineer for resolution, with the costs of such resolution borne equally by the parties (or by the losing party, at Seller's option if we can negotiate it).
These refinements will provide certainty around payment timing and avoid the potential for Buyer to delay verification — and thus delay payment — by raising objections to the generation data.
C. Indemnity Holdback
The Term Sheet provides that 15% of each annual transfer payment shall be deposited in escrow with Commonwealth Fiduciary Trust Company. Based on the estimated Year 1 transfer consideration of $23,271,803, the Year 1 holdback amount would be approximately $3,490,770. Escrow funds are to be released 36 months after the date of the applicable escrow deposit, subject to any outstanding or pending indemnity claims at the time of the scheduled release.
The Term Sheet further provides that all interest earned on escrowed funds shall accrue for the benefit of Buyer.
Commentary. The 15% holdback rate is at the higher end of the market range for IRC § 6418 credit transfer transactions, where holdback rates typically fall between 10% and 15%. Several recent comparable transactions have been executed with holdbacks of 10% to 12.5%, particularly where the credit generator is a well-capitalized entity with a strong credit profile and where recapture insurance is in place. The 36-month release period is consistent with market practice and is generally acceptable, as it provides a sufficient window for IRS audit activity while not imposing an unreasonable cash drag on Seller.
However, the provision directing all interest on escrowed funds to Buyer is decidedly non-market. The prevailing market convention is for interest to follow the principal — that is, interest earned on funds that are ultimately released to Seller accrues for Seller's benefit, while interest earned on funds that are retained in escrow to satisfy sustained indemnity claims accrues for Buyer's benefit. The Buyer's formulation effectively converts the holdback into an interest-free loan from Seller to Buyer for the 36-month escrow period, which is an additional economic concession beyond the holdback itself.
C&H recommends the following negotiation positions with respect to the holdback:
(a) Reduce the holdback rate from 15% to 10%, or to 12.5% as a compromise position. The reduction is particularly warranted if Seller procures recapture insurance from Northfield Specialty Insurance Co. that provides an independent credit enhancement.
(b) Negotiate for interest on escrowed funds to follow the principal, as described above.
(c) Clarify that "pending indemnity claims" that delay release must be supported by a written notice specifying in reasonable detail the factual basis for the claim and the estimated amount, and that unsubstantiated claims may not delay release.
D. Scope and Term
The Term Sheet covers all PTCs generated by the Ridgeway Wind Project for taxable years 2025 through 2034, representing the full 10-year PTC eligibility period. The arrangement is structured as an exclusive transfer commitment — Seller may not transfer credits generated by the Project to any other party during the term of the agreement.
In addition, the Term Sheet grants Buyer a right of first offer ("ROFO") on any additional transferable credits generated by any DEH affiliate during the term of the agreement. The ROFO requires Seller to notify Buyer of any proposed credit transfer by any DEH affiliate and to offer Buyer the opportunity to match or exceed the terms of any competing offer before the credits may be transferred to a third party.
Commentary. The exclusivity provision with respect to the Ridgeway Wind Project is standard and expected for a transaction of this type. However, the ROFO on credits from other DEH affiliate projects is overly broad and presents significant commercial concerns. DEH is currently developing or has in various stages of development additional renewable energy projects across the western United States, including at least two additional wind projects and a utility-scale solar-plus-storage project. Granting Pinnacle a ROFO over credits from all of these projects would significantly constrain DEH's ability to obtain competitive pricing and terms for credit transfers from those projects, effectively converting a single-project transfer arrangement into a portfolio-level commitment.
C&H recommends either: (a) deleting the ROFO entirely, on the basis that it is not reasonably related to the Ridgeway Wind Project transaction and imposes an undue commercial restriction on DEH's broader development business; or (b) narrowing the ROFO to credits generated solely by the Ridgeway Wind Project, which would give Buyer comfort that any incremental credits from the same facility would be offered to Buyer first but would preserve DEH's flexibility with respect to its other projects.
E. Conditions Precedent to Buyer's Obligation to Purchase
The Term Sheet sets forth the following conditions precedent to Buyer's obligation to purchase credits in any given taxable year:
(i) Seller shall have obtained an IRS pre-filing registration number for the applicable taxable year under Treas. Reg. § 1.6418-4 via the IRS Energy Credits Online portal.
(ii) Seller shall have delivered to Buyer an updated PTC eligibility opinion from Seller's tax advisor, Grayson Birch & Co. LLP, in form and substance reasonably satisfactory to Buyer.
(iii) Seller shall have delivered to Buyer an annual energy production report from the independent engineer, Meridian Technical Advisors LLC, certifying actual electricity generation for the applicable taxable year.
(iv) No "material adverse change in law" shall have occurred that affects IRC § 6418 transfer elections or IRC § 45 PTCs.
(v) No recapture event under IRC § 45 shall have occurred or be reasonably expected to occur.
(vi) Seller's representations and warranties shall be true and correct in all material respects as of each annual closing date.
(vii) Redstone Capital Bank, N.A.'s prior written consent to the transfer shall have been obtained and shall remain in full force and effect.
Commentary. The conditions precedent are largely standard for transactions of this type. However, the "material adverse change in law" condition, as currently drafted, is excessively broad. The Term Sheet does not define "material adverse change in law" and, as written, the condition would encompass not only enacted legislation and final Treasury regulations, but also proposed legislation, proposed regulations, administrative guidance (including IRS Notices, Revenue Rulings, and even informal guidance), and potentially even public statements by Treasury officials or members of Congress regarding possible future changes. This breadth would give Buyer an essentially unfettered right to refuse to purchase credits in any year in which there is any legislative or regulatory uncertainty affecting PTCs or § 6418 transfers — a condition that, given the current political environment, could be triggered at virtually any time.
C&H recommends narrowing the "material adverse change in law" condition to encompass only: (a) enacted legislation (i.e., legislation that has been signed into law by the President) that actually eliminates or materially reduces the eligibility for, or the amount of, PTCs under IRC § 45 or the ability to transfer such credits under IRC § 6418; or (b) final Treasury regulations (i.e., regulations that have been published in the Federal Register in final form, not proposed or temporary regulations) that have the same effect. Proposed legislation, proposed regulations, administrative guidance, and IRS audit activity should be expressly excluded from the definition.
Additionally, the condition regarding recapture events should be limited to actual recapture events that have occurred, rather than events that are "reasonably expected" to occur, as the latter standard is subjective and could be used by Buyer as a pretext for declining to close.
F. IRS Registration
The Term Sheet provides that Seller is responsible for completing IRS pre-filing registration under Treas. Reg. § 1.6418-4 for each taxable year. Registration must be filed within 30 days of the end of each taxable year. Buyer has the right to review and approve the registration submission before filing.
Commentary. The 30-day filing deadline is considerably tighter than required under the Treasury Regulations, which generally require registration before the due date of the transferee's return (including extensions). While Seller should aim for prompt registration to facilitate timely payment, a 30-day post-year-end deadline is operationally challenging, particularly for the first year of the arrangement when the registration process may involve additional coordination. C&H recommends extending the registration deadline to 60 days following the end of each taxable year, which provides adequate time for data compilation and review while still ensuring registration occurs well in advance of the filing deadline.
Additionally, Buyer's "review and approve" right over the registration submission is currently unrestricted. This could enable Buyer to delay registration — and thus delay the trigger for its own payment obligation — by withholding or conditioning approval. C&H recommends that Buyer's approval right be limited to review for factual accuracy and that approval may not be unreasonably withheld, conditioned, or delayed. Buyer should be required to provide any comments or objections within a specified period (we suggest five business days) after receipt of the draft registration, failing which approval shall be deemed given.
IV. Seller Representations and Warranties — Analysis and Commentary
The Term Sheet requires Seller to make a comprehensive set of representations and warranties, which would be brought down at each annual closing date. We address each category of representations below.
A. Credit Eligibility Representations
The Term Sheet requires Seller to represent and warrant that:
(a) RWE is an "eligible taxpayer" as defined in IRC § 6418(a) and Treas. Reg. § 1.6418-1, with the capacity to make a valid transfer election under IRC § 6418;
(b) The Ridgeway Wind Project is a "qualified facility" under IRC § 45(d), satisfying all applicable requirements for PTC eligibility;
(c) The Project was placed in service on November 14, 2025, as certified by Meridian Technical Advisors LLC; and
(d) All PTCs generated by the Project have been and will be properly calculated in accordance with IRC § 45 and the applicable Treasury Regulations.
Commentary. These representations are generally appropriate and expected in a transaction of this type. However, certain of these representations should be qualified in recognition of the fact that Seller's determinations on these matters are based, in significant part, on the advice and analysis of third-party experts. Specifically:
• The determination that RWE is an "eligible taxpayer" under § 6418 and that the Project is a "qualified facility" under § 45(d) is based on the legal analysis being prepared by Grayson Birch & Co. LLP in its PTC eligibility memorandum. Seller should be entitled to qualify these representations with a knowledge qualifier (e.g., "to Seller's knowledge") to the extent Seller is relying on Grayson Birch's analysis.
• The placed-in-service date representation is based on Meridian's COD certification. While Seller has no reason to doubt the certification, any representation as to placed-in-service date should reference the COD certification as the basis for the representation.
• The representation that PTCs "will be" properly calculated on a forward-looking basis throughout the 10-year eligibility period is inherently speculative, as it depends on future generation data, future inflation adjustments, and the continued satisfaction of various eligibility requirements. C&H recommends converting this to a backward-looking representation (PTCs "have been" properly calculated for each applicable year as of the closing date) and addressing prospective eligibility through the conditions precedent and annual bring-down mechanism.
Additionally, C&H recommends adding a general carve-out for changes in IRS interpretation or administrative practice that could affect credit eligibility, to the extent such changes are not attributable to any act or omission of Seller.
B. Prevailing Wage and Apprenticeship Compliance
The Term Sheet requires Seller to represent and warrant that:
(a) The Project has satisfied, and will continue to satisfy throughout the 10-year PTC eligibility period, all prevailing wage and apprenticeship requirements under IRC § 45(b)(6) and the applicable Treasury Regulations necessary for the 5x bonus credit multiplier; and
(b) This representation survives for the full 10-year PTC eligibility period plus 36 months (i.e., through approximately December 31, 2037).
Commentary. This is one of the most significant risk areas in the Term Sheet, and we urge DEH to review this issue carefully. The prevailing wage and apprenticeship representation is absolute — it is not qualified by knowledge, materiality, or any threshold. It is both backward-looking (covering the construction period from approximately April 6, 2023, through the commercial operations date on November 14, 2025) and forward-looking (covering ongoing operations throughout the PTC eligibility period).
With respect to the construction period, the prevailing wage and apprenticeship requirements are satisfied by the general contractor and its subcontractors, many of whom were not under the direct supervision or control of RWE. While RWE included prevailing wage and apprenticeship compliance obligations in its EPC contract and monitored compliance through periodic reporting, absolute compliance across all trades and all subcontractor tiers over a multi-year construction period is difficult to guarantee with certainty. C&H recommends that DEH conduct a thorough review of prevailing wage compliance records from the construction phase. We understand that Angela Whitfield (VP, Renewables Development) oversaw the construction compliance program, and we recommend that the compliance records be verified and organized in a form that can be produced to Buyer's counsel during the due diligence process to support this representation.
With respect to the forward-looking component, ongoing prevailing wage compliance for operations and maintenance activities should be more manageable, as the labor force is smaller and under more direct control. Nevertheless, an absolute forward-looking representation creates exposure for events that may not yet have occurred and may be outside of Seller's immediate knowledge.
C&H recommends the following modifications:
(a) The backward-looking representation should be qualified to Seller's knowledge, based on Seller's review of available compliance records and certifications from the general contractor and subcontractors.
(b) The forward-looking representation should be subject to a commercially reasonable efforts covenant (i.e., Seller covenants to use commercially reasonable efforts to maintain compliance) rather than an absolute representation.
(c) The survival period should be capped at the PTC eligibility period (10 years) plus the applicable statute of limitations under the Code. The general statute of limitations under IRC § 6501(a) is three years from the date of filing the return, and the extended statute of limitations under IRC § 6501(e) is six years in the case of a substantial omission of income. Thus, the maximum survival period should be 10 years plus 6 years (i.e., through approximately 2040), rather than the Term Sheet's formulation of 10 years plus 36 months. We note that the 36-month figure in the Term Sheet is actually shorter than the statute of limitations, which may be an oversight by HL&S, but C&H recommends using the statute of limitations as the governing benchmark for all survival periods, as it provides a principled and defensible framework.
C. Energy Community Qualification
The Term Sheet requires Seller to represent and warrant that:
(a) The Project is located in an "energy community" as defined in IRC § 45(b)(11)(B), qualifying for the 10% energy community bonus credit; and
(b) Custer County, Montana meets the census tract criteria for historical fossil fuel employment established by the IRS for purposes of the energy community designation.
Commentary. The energy community designation is determined on an annual basis by the IRS, based on data published by the Bureau of Labor Statistics and other federal agencies. The list of qualifying energy communities is updated periodically, and a county that qualifies in one year may be removed from the list in a subsequent year due to changes in employment data or methodological revisions. The Term Sheet, as currently drafted, places the entire risk of future de-designation on Seller through an absolute representation. This is problematic because Seller has no control over the IRS's annual determination of which communities qualify.
C&H recommends the following approach:
(a) The representation should be limited to a statement that the Project qualified as being located in an energy community as of the commercial operations date (November 14, 2025) and as of the most recent IRS publication of the energy community list as of each annual closing date.
(b) In the event the Project ceases to qualify for the energy community bonus in a future taxable year due to changes in the IRS's annual determination, the consequence should be an adjustment to the transfer consideration for that year (i.e., the credits transferred would be valued at the non-energy-community rate of $0.0275/kWh rather than $0.03025/kWh, and the transfer price would be applied to the lower credit amount), rather than an indemnification claim against Seller.
(c) The adjustment mechanism should be clearly documented in the definitive agreement as a pricing adjustment, not a breach of representation, to avoid triggering the indemnification provisions.
This approach allocates the energy community risk in a manner that is proportionate — Buyer pays less if the bonus is not available, but Seller is not exposed to indemnification liability for an event entirely outside its control.
D. No Tax-Exempt Use Property
The Term Sheet requires Seller to represent that no portion of the Project constitutes "tax-exempt use property" under IRC § 168(h). This representation is relevant because the transfer of credits from property that constitutes tax-exempt use property would be subject to certain limitations under the Code.
Commentary. This representation is standard and appropriate. Based on our review of the Project's ownership structure and the PPA, we have no reason to believe that any portion of the Project constitutes tax-exempt use property. Great Plains Municipal Power Authority, as the PPA counterparty, is a political subdivision, but the PPA is a standard energy purchase agreement and does not involve a sale-leaseback or other arrangement that would cause the Project to be treated as tax-exempt use property. No changes to this representation are recommended.
E. Organizational Representations
The Term Sheet requires Seller to represent that:
(a) RWE is duly organized, validly existing, and in good standing as a limited liability company under the laws of the State of Delaware (Secretary of State file number 7603517);
(b) DRI is the sole member of RWE, and DRI is a wholly owned subsidiary of DEH;
(c) All necessary corporate and organizational authorizations for the execution, delivery, and performance of the transfer agreement have been obtained from RWE, DRI, and DEH; and
(d) The execution, delivery, and performance of the transfer agreement will not violate any provision of the organizational documents of RWE, DRI, or DEH or any agreement to which any such entity is a party.
Commentary. These organizational representations are standard and generally acceptable. C&H notes that confirmation of board-level authorization at DEH will be necessary prior to execution of the definitive agreement. Callum Dunmore holds a 68% equity interest in DEH and serves as Chairman of the board. C&H recommends that Marcus Petrov and Fiona Kessler confirm that Mr. Dunmore has been briefed on the proposed transaction and that the DEH board will authorize the transaction at or prior to the time of execution. If DEH's organizational documents require a supermajority vote or other specific approval mechanics for transactions of this nature, those should be reviewed and satisfied in advance.
V. Indemnification Provisions — Analysis and Commentary
The indemnification provisions in the Term Sheet are among the most significant areas requiring negotiation. As currently drafted, the indemnification framework tilts heavily in Buyer's favor and would expose Seller and its parent entities to uncapped, broadly defined liability. We address each component below.
A. Scope of Seller Indemnification
The Term Sheet provides that Seller (RWE), together with a parent guarantee from DRI and DEH, shall indemnify and hold harmless Buyer against:
(i) Any disallowance, reduction, or recapture of transferred credits by the IRS, regardless of the cause;
(ii) Any breach of any representation or warranty made by Seller in the transfer agreement;
(iii) Any penalties, interest, or additional tax assessed against Buyer as a result of a credit deficiency arising from or related to the transferred credits; and
(iv) Any "excessive credit transfer" under IRC § 6418(g) resulting in the imposition of the 20% penalty on Buyer.
Commentary. The indemnification scope as drafted is extremely broad and presents several significant concerns from Seller's perspective:
Category (i) — Disallowance, Reduction, or Recapture. The use of the word "any" without qualification means that Seller would be liable for credit adjustments regardless of cause, including adjustments attributable to changes in law enacted after the applicable taxable year, IRS administrative reinterpretations, mathematical errors by Buyer in claiming the credits on its return, or production shortfalls below the P50 estimate. This is unreasonable — Seller should only be responsible for credit deficiencies attributable to Seller's own acts, omissions, or breaches.
Category (iii) — Penalties, Interest, and Additional Tax. The indemnification for penalties and interest assessed against Buyer is appropriate in cases where the penalty or interest arises from Seller's breach of a representation (e.g., if Seller misrepresented prevailing wage compliance, leading to a loss of the 5x multiplier and an IRS assessment against Buyer). However, the Term Sheet does not limit this indemnity to cases where Seller is at fault. As written, Seller would be liable for penalties and interest arising from general market or legal risk (e.g., an IRS challenge to the energy community designation) or from Buyer's own errors in claiming the credits. C&H recommends limiting this indemnity to penalties and interest that arise directly from a breach of Seller's representations or covenants.
Category (iv) — Excessive Credit Transfer Penalty. Under IRC § 6418(g), if the amount of a transferred credit exceeds the amount of credit to which the transferor was entitled, the excess is treated as an underpayment of tax by the transferee, subject to a 20% penalty. The Term Sheet shifts the entire risk of this penalty to Seller. While it is appropriate for Seller to bear this risk to the extent the excess results from Seller's own miscalculation or misrepresentation, the penalty can also arise from Buyer's own errors in claiming the credit (e.g., if Buyer claims a greater amount than was transferred, or fails to account for a partial-year transfer). C&H recommends that Seller's indemnification for the § 6418(g) penalty be limited to cases where the excess results from (a) a breach of Seller's representations or warranties, or (b) Seller's provision of inaccurate information used to determine the credit amount, and should expressly exclude cases where the excess results from Buyer's own errors in preparing or filing its return.
B. Indemnification Cap
The Term Sheet does not include any cap on Seller's aggregate indemnification liability.
Commentary. This is a critical deficiency from Seller's perspective and represents the single most important negotiation item identified in this memorandum. In the absence of a cap, Seller's indemnification exposure is theoretically unlimited and could, in an extreme scenario, exceed the aggregate transfer consideration received over the 10-year term. The absence of a cap is not market standard — virtually all recent IRC § 6418 credit transfer agreements that we have reviewed include some form of indemnification cap.
C&H strongly recommends negotiating an aggregate cap on Seller's indemnification liability. Our recommended structure is as follows:
(a) Annual Cap for Non-Fundamental Representations: Seller's aggregate indemnification liability for breaches of non-fundamental representations and warranties (e.g., organizational representations, no-tax-exempt-use-property) in any given taxable year should be capped at 100% of the transfer consideration received by Seller for that taxable year.
(b) Aggregate Cap for Fundamental Representations: Seller's aggregate indemnification liability for breaches of fundamental representations (e.g., credit eligibility, prevailing wage compliance, placed-in-service date) over the life of the agreement should be capped at 100% of the cumulative transfer consideration received by Seller to date as of the date of the indemnification claim.
(c) The cap should be inclusive of all costs, expenses, penalties, interest, and losses of any kind for which Seller is obligated to indemnify Buyer.
(d) The cap should not apply to claims arising from Seller's fraud or willful misconduct, which should remain uncapped.
We anticipate that Pinnacle may resist a cap or propose a higher cap (e.g., 150% of consideration). Our fallback position should be no lower than 100% of cumulative consideration received.
C. Indemnification Basket and De Minimis Threshold
The Term Sheet does not include any basket or de minimis threshold for indemnification claims.
Commentary. The absence of a basket or de minimis threshold means that Seller would be liable for the first dollar of any indemnified loss, regardless of how small or immaterial the claim may be. This creates the potential for nuisance claims and imposes a disproportionate administrative burden relative to the amounts involved.
C&H recommends the following:
(a) De Minimis Threshold: Individual indemnification claims below $50,000 should not be actionable and should not count toward the aggregate basket.
(b) Deductible Basket: Seller's indemnification obligations should not attach until the aggregate amount of all qualifying claims (i.e., claims exceeding the de minimis threshold) exceeds 1% of the annual transfer consideration for the applicable taxable year, which based on Year 1 figures would be approximately $233,000. Once the basket is exceeded, Buyer should be entitled to recover only the amount in excess of the basket (i.e., the basket functions as a true deductible, not a tipping basket).
(c) The de minimis threshold and basket should not apply to breaches of fundamental representations or to claims involving fraud or willful misconduct.
D. Recapture Indemnification
The Term Sheet provides that Seller shall indemnify Buyer for any recapture of PTCs under IRC § 45 and applicable Treasury Regulations. The Term Sheet identifies the following recapture triggers:
(a) Disposition of the Project or a change of ownership of RWE;
(b) Cessation of electricity production by the Project;
(c) Failure to maintain prevailing wage and apprenticeship compliance; and
(d) Any event that causes the Project to cease being a "qualified facility" under IRC § 45(d).
Commentary. Recapture indemnification is a standard feature of IRC § 6418 credit transfer agreements, and the general obligation to indemnify Buyer for recaptured credits is appropriate. However, the specific trigger list as drafted is overly inclusive and fails to account for ordinary-course operational events that should not give rise to indemnification liability.
Most significantly, the "cessation of electricity production" trigger (item (b) above) is drafted without any qualifications. As written, it would encompass:
• Temporary curtailments due to grid congestion or MISO dispatch orders;
• Force majeure events such as severe weather, natural disasters, or equipment failures;
• Scheduled maintenance outages;
• Grid interruptions or transmission system outages caused by NorthStar Transmission Holdings LLC or other third parties; and
• Brief operational interruptions that are routine in the operation of a wind farm.
None of these events should constitute a "cessation of electricity production" giving rise to recapture under IRC § 45 or indemnification liability under the transfer agreement. The recapture provisions under IRC § 45 and the applicable Treasury Regulations contemplate a permanent or extended cessation of the facility's operations, not temporary or routine interruptions.
C&H recommends the following modifications:
(a) The recapture triggers should be drafted by cross-reference to the specific recapture provisions in IRC § 45 and Treas. Reg. §§ 1.45-1 through 1.45-13, rather than using a freestanding, catch-all formulation that may be broader than the statutory and regulatory provisions.
(b) The "cessation of electricity production" trigger should be expressly qualified to exclude temporary curtailments, force majeure events, scheduled maintenance, grid interruptions attributable to the transmission provider, and any operational interruption lasting fewer than a specified number of consecutive days (we suggest 180 days as a threshold for a material cessation).
(c) The catch-all trigger (item (d) above) should be deleted or narrowed, as it is subsumed by the specific triggers and adds only ambiguity.
E. Recapture Insurance as Backstop
The Term Sheet contemplates that Seller will procure tax credit recapture insurance at Seller's sole cost and expense. The Term Sheet does not specify the required coverage amount, the identity of the insurer, or the terms of the policy.
Commentary. C&H recommends that DEH promptly engage Corbin Hale & Associates Inc. (Steven Rask, lead broker) to obtain a recapture insurance policy from Northfield Specialty Insurance Co. (80 Pine Street, New York, NY 10005). Recapture insurance has become increasingly available in the IRC § 6418 credit transfer market and serves as an important risk mitigation tool for both parties.
The key parameters of the insurance engagement should include:
(a) Coverage Scope: The policy should cover the key recapture triggers identified in the transfer agreement, including disposition of the Project, cessation of operations, and loss of prevailing wage compliance.
(b) Coverage Limit: The coverage limit should be coordinated with the indemnification cap negotiated in the transfer agreement. If, for example, Seller negotiates an indemnification cap at 100% of cumulative consideration received, the insurance policy should ideally provide coverage up to at least a substantial portion of that amount. Alternatively, the policy limit could be set at a negotiated amount that reflects the parties' assessment of the realistic maximum exposure.
(c) Named Insured / Loss Payee: Buyer will likely request — and C&H recommends agreeing — that Buyer be named as an additional insured or loss payee on the Northfield policy. This ensures that Buyer has direct recourse to the insurer in the event of a recapture event, independent of Seller's ability to satisfy its indemnification obligations.
(d) Policy Term: The policy should cover the full PTC eligibility period (TY2025 through TY2034) plus the applicable survival period.
(e) Premium: The cost of the premium will be borne by Seller. C&H recommends obtaining a preliminary quotation from Northfield before finalizing the indemnification cap negotiation, as the availability and cost of insurance coverage will directly inform the parties' negotiation positions. If the premium is reasonable relative to the risk reduction it provides, it may be advantageous for Seller to obtain more robust coverage than strictly necessary in order to support a lower holdback rate and a more favorable indemnification cap.
F. Survival of Indemnification Obligations
The Term Sheet provides that indemnification obligations survive for 36 months following the expiration of the 10-year PTC eligibility period, i.e., through taxable year 2037.
Commentary. The 36-month survival period following the end of the PTC eligibility period is consistent with the escrow release mechanics and is generally acceptable in principle. However, as discussed in Section IV.B above in connection with the prevailing wage representation, C&H recommends that all survival periods be tied to the applicable statute of limitations under the Code. For general representations, survival should extend through the PTC eligibility period plus three years (per IRC § 6501(a)). For fundamental representations (including credit eligibility and prevailing wage compliance), survival should extend through the PTC eligibility period plus six years (per IRC § 6501(e)). This approach provides a principled and defensible framework that is tied to the period during which the IRS could actually assess a deficiency.
VI. Definition of "Disallowance Event" — Analysis and Commentary
The Term Sheet defines "Disallowance Event" as:
> "any event, act, omission, change in law, IRS determination, or other circumstance that results in the disallowance, reduction, adjustment, or recapture of any transferred PTC, in whole or in part."
Commentary. This definition is unacceptably broad and is, in C&H's view, the single most overreaching provision in the Term Sheet (other than the absence of an indemnification cap). The definition as drafted encompasses virtually any circumstance that could result in a credit being worth less than the amount estimated at the time of transfer, regardless of the cause. Specifically, the current definition would capture:
(a) Changes in law — including retroactive changes to IRC § 45 or IRC § 6418, which are entirely beyond Seller's control. Seller should not be liable for credit reductions caused by Congressional action taken after the credits have already been generated and transferred.
(b) IRS audit adjustments that are contested and not final — under the current definition, an IRS notice of deficiency or proposed adjustment would constitute a "Disallowance Event" even before the matter has been finally resolved. This would trigger indemnification obligations and potentially permit Buyer to draw on the escrow before there is any final determination that the credits were improper.
(c) Reductions due to curtailment or lower-than-expected generation — the current definition encompasses "reduction" of transferred PTCs, which could include situations where actual electricity generation is lower than the P50 estimate used to calculate the estimated credit amount. Lower generation is a production risk, not a credit eligibility risk, and should be addressed through the true-up mechanism (which adjusts the transfer consideration based on actual generation) rather than through indemnification.
(d) Inflation adjustments — if the base PTC rate as adjusted for inflation in a future year is lower than the rate assumed in the initial credit estimate, the resulting "reduction" in the credit amount could technically fall within this definition. This is clearly not a risk that should be allocated to Seller through indemnification.
C&H recommends that the definition of "Disallowance Event" be substantially narrowed to encompass only the following:
(a) A final, non-appealable determination by the IRS (whether by notice of deficiency that is not timely contested, a closing agreement, or a final court order) or by a court of competent jurisdiction that all or a portion of the transferred credits were not eligible for transfer under IRC § 6418, were not properly calculated under IRC § 45, or were otherwise improperly claimed by Buyer in reliance on the transfer;
(b) A recapture event specifically enumerated under IRC § 45 and the applicable Treasury Regulations (as narrowed in accordance with our recommendations in Section V.D above); and
(c) A breach of a specific representation or warranty made by Seller in the transfer agreement, to the extent such breach directly causes a disallowance, reduction, or recapture of transferred credits.