1015-00002 · Calloway-Briggs Renewables Inc · Analysis & Advice

memo-itc-eligibility-ppa-structure.docx DOCUMENT M&A / Corporate

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PRIVILEGED AND CONFIDENTIAL — ATTORNEY-CLIENT COMMUNICATION / ATTORNEY WORK PRODUCT

MEMORANDUM

TO: Patricia Dunmore, Responsible Partner, Energy & Infrastructure Brett Callahan, Lead Associate, Energy & Infrastructure

FROM: Samuel Reeves, Associate, Tax

DATE: July 18, 2025

RE: Saguaro Flats Solar Project — ITC Eligibility Under IRC § 48 and Impact of Virtual PPA / CfD Structure on Tax Credit Qualification

MATTER NO.: 1015-00002

CLIENT: Calloway-Briggs Renewables Inc.

I. Executive Summary

Calderwood & Harkness LLP represents Calloway-Briggs Renewables Inc. ("CBR") in connection with the negotiation of a twenty-year virtual power purchase agreement (the "PPA") with Meridian DataCore Solutions Inc. ("Meridian" or "Buyer") for the output of the Saguaro Flats Solar Project (the "Project"), a 150 MWac (195 MWdc) ground-mounted single-axis tracking solar photovoltaic facility to be developed, constructed, and operated on an approximately 1,400-acre site in Pecos County, Texas. The PPA is structured as a contract for differences ("CfD") settling at the ERCOT West Hub. It is not a physical power sale. Under the CfD, Buyer pays Seller the Contract Price ($20.00/MWh, fixed for years one through five, escalating at 1.50% per annum compounding in years six through twenty) for each MWh generated, with net settlement against the ERCOT West Hub spot price.

The Project will be owned by Saguaro Flats Solar LLC, a Delaware limited liability company wholly owned by CBR. Saguaro Flats Solar LLC is the contractual Seller under the PPA and will own all tangible and intangible assets associated with the Project, including modules, inverters, trackers, balance-of-system equipment, the interconnection facilities on the Seller's side of the point of interconnection, and all environmental attributes and renewable energy certificates generated by the facility.

This memorandum has been prepared at the request of the Energy & Infrastructure practice group to analyze whether the Saguaro Flats Solar Project qualifies for the Investment Tax Credit ("ITC") under Section 48 of the Internal Revenue Code of 1986, as amended (the "Code" or "IRC"), at the full 30% rate (assuming satisfaction of prevailing wage and apprenticeship requirements), the estimated dollar value of the ITC based on the current engineering, procurement, and construction ("EPC") contract price, and — most critically — whether the virtual PPA / CfD structure creates any risk to ITC qualification. The estimated ITC value, based on a $142,500,000 fixed-price turnkey EPC contract with Sunbelt Power Construction LLC ("Sunbelt"), is approximately $42,750,000, a figure that is central to the Project's economics and to the lender group's underwriting of the $108,000,000 senior secured construction-to-term loan facility being arranged by Tralvendo National Bank, N.A. ("Tralvendo").

Conclusion. Based on the analysis set forth below, it is our opinion that the CfD structure does not jeopardize ITC eligibility. Saguaro Flats Solar LLC will retain tax ownership of the facility and will be the proper taxpayer to claim the ITC, provided that (a) certain PPA language is included to preserve Seller's ownership position and to preclude recharacterization arguments, (b) the Project satisfies all statutory and regulatory requirements for the ITC, including the prevailing wage and apprenticeship requirements enacted by the Inflation Reduction Act of 2022 (the "IRA"), and (c) no transfer or disposition occurs during the five-year recapture period under IRC § 50(a) that would cause the facility to cease to be investment credit property. Specific drafting recommendations are set forth in Section VI below, and we recommend that they be incorporated into the Seller's Revised Draft PPA (Second Draft), which is targeted for circulation to Meridian's counsel on August 11, 2025.

II. Background — Project and Transaction Structure

A. Project Overview

The Saguaro Flats Solar Project is a utility-scale ground-mounted solar photovoltaic generation facility with a nameplate direct current ("DC") capacity of 195 MWdc and an alternating current ("AC") capacity of 150 MWac, yielding a DC-to-AC ratio of approximately 1.30. The facility will employ single-axis tracking technology, which is expected to optimize energy production by adjusting the angle of the photovoltaic modules to follow the sun's east-to-west path throughout the day. This technology is industry-standard for utility-scale solar installations in West Texas and is well-suited to the high direct normal irradiance characteristic of the Project site.

The Project is located on approximately 1,400 acres situated along FM Road 1776, approximately twelve miles southeast of Fort Stockton, Pecos County, Texas 79735. The site is leased from Redrock Mesa Ranch LP ("Redrock") under a thirty-five-year ground lease (the "Ground Lease"), with two ten-year extension options exercisable at Saguaro Flats Solar LLC's discretion. The Ground Lease was executed on March 22, 2025 and provides for annual rent escalating at 1.25% per annum, with a one-time construction disturbance payment due at the commencement of civil works.

Sunbelt Power Construction LLC, an established solar EPC contractor based in Austin, Texas, has been engaged as the Project's EPC contractor under a fixed-price turnkey EPC contract (the "EPC Contract") with a contract value of $142,500,000. The EPC Contract scope includes engineering and design, procurement of all major equipment (modules, inverters, single-axis trackers, racking, transformer, and balance-of-system components), civil works and site preparation, installation and commissioning, and performance testing. The EPC Contract was executed on June 1, 2025, and Sunbelt has issued a notice to proceed, with mobilization expected to commence in the fourth quarter of 2025.

Total estimated project cost is approximately $154,300,000, which includes the EPC contract value of $142,500,000 plus approximately $11,800,000 in soft costs, including land acquisition and lease costs, permitting fees, environmental and cultural resource assessments, interconnection costs, development-stage legal and advisory fees, insurance premiums, contingency reserves, and financing costs during the construction period.

The expected commercial operation date ("COD") is April 1, 2027, consistent with the milestone schedule set forth in the EPC Contract and the construction loan drawdown schedule. Achievement of COD under the PPA requires, among other things, (i) completion of construction and commissioning, (ii) successful completion of the performance test demonstrating the facility's ability to generate electricity at or above the guaranteed minimum capacity, (iii) interconnection to ERCOT and receipt of all required approvals and certifications from ERCOT, and (iv) execution of all required revenue metering agreements.

The Project will interconnect to the ERCOT grid at the Ft. Stockton 345 kV Substation via transmission facilities owned and operated by West Texas Wires LLC. A Large Generator Interconnection Agreement ("LGIA") was executed on May 15, 2025 (ERCOT Queue Position ERCOT-GI-2024-0437), and the interconnection study process has been completed. The estimated interconnection cost, which is included in the $11,800,000 soft cost budget, is approximately $4,200,000, consisting primarily of network upgrade costs and the Seller's share of substation expansion costs.

An independent solar resource assessment was performed by Heliograph Energy Consulting LLC ("Heliograph"), a nationally recognized solar resource consultancy, utilizing on-site pyranometer data collected over a fourteen-month measurement campaign (January 2024 through February 2025), satellite-derived irradiance data, and industry-standard modeling software. Heliograph's assessment concluded that the Project's P50 annual net generation (after accounting for soiling, module degradation, electrical losses, availability, and curtailment assumptions) is approximately 350,000 MWh per year, with a P90 estimate of approximately 315,000 MWh per year.

B. Ownership Structure

Saguaro Flats Solar LLC is a Delaware limited liability company (EIN 93-1284506) formed on January 10, 2025, for the sole purpose of developing, constructing, owning, and operating the Project. Saguaro Flats Solar LLC is 100% owned by CBR (Delaware corporation, EIN 82-4637201) and is treated as a disregarded entity for federal income tax purposes. As a disregarded entity, all items of income, deduction, gain, loss, and credit attributable to Saguaro Flats Solar LLC — including the ITC — flow through to CBR as the sole member. CBR will accordingly be the taxpayer that claims the ITC on its federal income tax return for the taxable year in which the Project is placed in service.

CBR is a Delaware corporation managed by its officers and board of directors. Lena Calloway-Briggs serves as CBR's Chief Executive Officer. The majority equity interest in CBR — approximately 68% of CBR's common equity — is held by Ridgepoint Capital Partners LP ("Ridgepoint"), a private equity fund managed by its general partner, Ridgepoint Capital Management LLC (Managing Partner: Alan Driscoll). The remaining approximately 32% of CBR's common equity is held by Lena Calloway-Briggs (18%), other members of CBR management (9%), and certain individual investors (5%). Ridgepoint's investment was made through a Series A preferred equity round closed in September 2023.

Saguaro Flats Solar LLC is the project company and will own all Project assets, including the solar photovoltaic generating equipment, balance-of-system components, the leasehold interest in the Project site under the Ground Lease, interconnection rights, permits and approvals, environmental attributes and renewable energy certificates, and all contractual rights, including its rights as Seller under the PPA. Saguaro Flats Solar LLC will be the counterparty Seller under the PPA with Meridian and will also be the borrower under the senior secured construction-to-term loan facility.

C. PPA Structure — Virtual PPA / Contract for Differences

The PPA between Saguaro Flats Solar LLC (as Seller) and Meridian DataCore Solutions Inc. (as Buyer) is structured as a virtual power purchase agreement, also commonly referred to in the industry as a "synthetic PPA" or "financial PPA." The economic substance of the PPA is a contract for differences — a bilateral financial settlement mechanism under which the parties settle the difference between a fixed contract price and a floating market price. The PPA term is twenty years, commencing on COD (expected April 1, 2027) and expiring on March 31, 2047.

The aggregate nominal contract value of the PPA over its twenty-year term is estimated at approximately $140,000,000, based on P50 annual generation of 350,000 MWh and the contract price escalation schedule. The contract price is structured as follows:

• Years 1 through 5 (April 1, 2027 – March 31, 2032): $20.00 per MWh (fixed)

• Years 6 through 20 (April 1, 2032 – March 31, 2047): $20.00 per MWh base, escalating at 1.50% per annum compounding (Year 6: $20.30/MWh; Year 10: $21.53/MWh; Year 15: $23.20/MWh; Year 20: approximately $25.02/MWh)

The settlement hub is the ERCOT West Hub, a liquid, transparent pricing node within the Electric Reliability Council of Texas market. The CfD settlement mechanics operate as follows:

(a) For each settlement period (expected to be monthly), the total MWh of electricity actually generated by the Project and metered at the revenue meter is determined (the "Delivered Quantity").

(b) The Seller receives the ERCOT West Hub spot price for each MWh generated by selling the electricity into the ERCOT real-time or day-ahead market. Seller retains all merchant revenue from ERCOT market sales.

(c) The CfD net settlement payment is calculated as follows: if the Contract Price exceeds the Hub Price for the applicable settlement period, the Buyer pays to Seller an amount equal to (Contract Price minus Hub Price) multiplied by the Delivered Quantity. If the Hub Price exceeds the Contract Price, Seller pays to Buyer an amount equal to (Hub Price minus Contract Price) multiplied by the Delivered Quantity.

(d) The net effect is that, in all market conditions, Seller's effective realized price per MWh for each settlement period equals the Contract Price — Seller receives the Hub Price from ERCOT market sales plus (or minus) the CfD settlement payment.

Critically, there is no physical delivery of electricity from Seller to Buyer under the PPA. Buyer does not take title to, or possession of, any electricity generated by the Project. Buyer does not schedule, dispatch, or nominate the Project's output. Buyer has no right to direct the operation of the facility. Settlement is purely financial — it is a payment obligation based on the difference between two prices applied to a metered quantity. In this respect, the PPA functions as a financial hedge or swap instrument, notwithstanding that it is documented as a power purchase agreement for commercial and counterparty credit purposes.

The expected contracted volume at P50 is approximately 7,000,000 MWh over the twenty-year PPA term (350,000 MWh per year multiplied by 20 years). Environmental attributes and renewable energy certificates ("RECs") associated with the Project's generation are addressed separately in the PPA; under the current draft, Buyer will receive all RECs generated by the Project, but the transfer of RECs is structured as a separate sale and does not affect the characterization of the CfD settlement mechanism or the tax ownership analysis.

D. Project Financing

The Project is being financed with a combination of equity and senior secured debt. Tralvendo National Bank, N.A. is serving as the Administrative Agent, Lead Arranger, and Bookrunner for a $108,000,000 senior secured construction-to-term loan facility (the "Credit Facility"). The Credit Facility is structured as a single-draw construction facility converting to a fully amortizing term loan upon achievement of COD and satisfaction of conversion conditions.

The syndicate of lenders participating in the Credit Facility is as follows:

The debt-to-equity ratio is approximately 70/30, with an equity contribution from CBR of approximately $46,300,000, sourced primarily from Ridgepoint's committed capital and CBR's retained earnings from its existing operating solar portfolio.

The interest rate on the Credit Facility is Term SOFR plus 175 basis points during the term loan period and Term SOFR plus 200 basis points during the construction period. The minimum debt service coverage ratio ("DSCR") covenant is 1.30x, and the Project is projected to achieve a DSCR of approximately 1.35x at P50 generation and Year 1 pricing, providing adequate cushion above the covenant threshold. The Credit Facility maturity is expected to be eighteen years from COD, with a sculpted amortization schedule tied to the Project's expected cash flows under the PPA.

Lender's counsel for the Credit Facility is Whitfield Stroval & Cade LLP, with Philip Thornton serving as lead partner. Whitfield Stroval will conduct its own legal due diligence on the PPA, the EPC Contract, the Ground Lease, the LGIA, and other material project documents, and will provide a lender's opinion in connection with the closing of the Credit Facility.

The ITC value is a critical component of the Project's economics and the lender group's underwriting. The approximately $42,750,000 ITC reduces CBR's federal income tax liability in the year the Project is placed in service (expected to be the 2027 taxable year), freeing cash that supports the equity return on the Project and provides a significant margin of safety in the financial model. The lender group's independent financial model review, performed by Llewellyn Capital Advisors LLC, incorporates the ITC at the 30% rate as a base case assumption. Any reduction in or loss of the ITC would materially impair the Project's financial viability and could result in a default under the Credit Facility.

III. ITC Eligibility Analysis Under IRC § 48

A. Statutory Framework

Section 48 of the Internal Revenue Code provides an investment tax credit for certain "energy property" placed in service by the taxpayer during the taxable year. The ITC is a dollar-for-dollar reduction in the taxpayer's federal income tax liability, calculated as a percentage of the eligible basis of the energy property. The ITC has been a cornerstone of federal policy supporting the development of renewable energy generating facilities for decades, and the credit mechanism has been extended and modified several times by Congress, most recently by the Inflation Reduction Act of 2022 (Pub. L. 117-169, enacted August 16, 2022).

Solar electric generating equipment is specifically enumerated as a category of energy property eligible for the ITC under IRC § 48(a)(3)(A)(i). This includes equipment that uses solar energy to generate electricity, including photovoltaic modules, inverters, transformers, racking and mounting systems, single-axis and dual-axis tracking systems, wiring, combiner boxes, switchgear, monitoring equipment, and related balance-of-system components that are integral to the generation of electricity from solar energy. The ITC for solar energy property has historically been the most widely utilized tax credit in the renewable energy sector.

The Inflation Reduction Act of 2022 made several significant modifications to the ITC framework for solar facilities. Most notably, the IRA established a two-tier credit rate structure: a base rate of 6%, and an increased rate of 30% available to projects that satisfy prevailing wage and apprenticeship requirements during construction and, in the case of the ITC, during the five-year recapture period for alteration and repair work. The IRA also introduced bonus credit adders for domestic content (an additional 10 percentage points) and location in an energy community (an additional 10 percentage points), potentially increasing the ITC rate to as high as 50% (or 70% in certain circumstances involving low-income community allocations, which are not applicable to the Project). The IRA extended the ITC for solar facilities through at least 2032, with a phase-down mechanism tied to greenhouse gas emissions reduction targets, and established alternative beginning-of-construction safe harbors.

For purposes of this memorandum, we assume that the Project will satisfy the prevailing wage and apprenticeship requirements and will qualify for the 30% ITC rate. The analysis of prevailing wage and apprenticeship compliance is addressed separately in Section V. We do not assume any bonus adders (energy community or domestic content) in our base ITC estimate; potential adders are discussed in Section VII.

B. Eligible Basis

The ITC is computed as a percentage of the taxpayer's "basis" in the energy property, as determined under the general basis rules of the Code. The eligible basis generally includes the cost of tangible personal property and other tangible property (not including a building or its structural components) that is used as an integral part of the solar generating facility. Under IRC § 48(a)(1), the amount of the energy credit for any taxable year is the energy percentage of the basis of each energy property placed in service during such taxable year.

The EPC contract price with Sunbelt Power Construction LLC is $142,500,000 on a fixed-price, turnkey basis. This contract price encompasses the design, engineering, procurement, construction, commissioning, and performance testing of the complete solar generating facility, including all major equipment (photovoltaic modules, string inverters, single-axis tracker systems, racking, medium-voltage collection system, project substation and step-up transformer, SCADA and monitoring systems), civil and structural works (grading, roads, drainage, fencing, foundations, pile driving), and electrical balance-of-system (AC and DC wiring, combiner boxes, switchgear, grounding systems). Based on our preliminary review, substantially all of the costs included in the EPC contract price relate to tangible personal property or other tangible property integral to the solar generating facility and are expected to qualify for inclusion in the eligible basis for ITC purposes.

The estimated ITC at the 30% rate is therefore:

30% × $142,500,000 = $42,750,000

This estimate is preliminary and is based on the assumption that substantially all EPC costs are includable in eligible basis. The eligible basis will need to be confirmed through a detailed cost segregation analysis, which should be performed by Aldgate & Pryor CPAs LLP (CBR's independent auditor) or a specialized engineering-based cost segregation firm. Certain cost categories within the EPC contract may require closer scrutiny, including:

(a) Site preparation costs — costs for grading, clearing, and drainage that are integral to the installation and operation of the solar facility are generally includable in basis, but costs attributable to general land improvements (e.g., roads primarily serving non-facility purposes) may not qualify;

(b) Interconnection costs — costs for electrical facilities on the Seller's side of the point of interconnection are generally includable, but costs for network upgrades owned by the transmission provider may not be;

(c) Fencing and security systems — fencing integral to the facility's operation and required by code or safety standards is generally includable;

(d) Commissioning and testing costs — these costs are generally includable as part of the cost of placing the energy property in service.

It is also important to note that the eligible basis does not include the cost of land or the leasehold interest in the Project site under the Ground Lease, nor does it include non-integral soft costs such as development-stage legal fees, financing costs, permitting fees, or insurance premiums incurred prior to the commencement of construction, to the extent such costs are not capitalized into the basis of the energy property under applicable tax accounting rules. The approximately $11,800,000 in soft costs included in the $154,300,000 total project cost is therefore excluded from our preliminary ITC calculation, although a portion of such costs (particularly interconnection costs) may ultimately be includable following the cost segregation study.

C. Placed-in-Service Requirement

The ITC is claimed in the taxable year in which the energy property is "placed in service." The placed-in-service date is a critical milestone for ITC purposes, as it determines (i) the year in which the credit is available, (ii) the commencement of the five-year recapture period under IRC § 50(a), and (iii) the beginning of the Modified Accelerated Cost Recovery System ("MACRS") depreciation period for the facility (the solar facility qualifies for five-year MACRS depreciation under IRC § 168, with 100% bonus depreciation available for projects placed in service before January 1, 2027, or potentially later depending on legislative developments).

Under Treasury Regulation § 1.46-3(d), property is considered "placed in service" in the earlier of (i) the taxable year in which the period for depreciation begins, or (ii) the taxable year in which the property is placed in a condition or state of readiness and availability for a specifically assigned function, whether in a trade or business, in the production of income, in a tax-exempt activity, or in a personal activity. For a solar generating facility, this generally means the date on which the facility is interconnected to the grid, has completed commissioning and performance testing, and is capable of generating and delivering electricity in commercial quantities.

The expected COD under the PPA is April 1, 2027. Achievement of COD under the PPA requires satisfaction of several conditions, including: (i) mechanical completion of the facility, (ii) interconnection to ERCOT and energization of the facility, (iii) successful completion of the performance test specified in the EPC Contract, (iv) receipt of all required governmental approvals and permits for commercial operation, and (v) execution of all metering and settlement agreements with ERCOT. These conditions are consistent with, and should satisfy, the placed-in-service standard under Treasury Regulation § 1.46-3(d). Assuming COD is achieved on April 1, 2027, the Project will be placed in service for ITC purposes in CBR's 2027 taxable year (CBR files on a calendar-year basis), and the ITC will be claimed on CBR's 2027 federal income tax return.

We note that if COD is delayed beyond December 31, 2027, the placed-in-service date would shift to the 2028 taxable year, which would defer the ITC claim by one year. The EPC Contract includes schedule guarantees and delay liquidated damages to mitigate this risk, and the current construction schedule includes approximately four months of schedule contingency. Based on our discussions with the project management team, a delay beyond December 31, 2027 is considered unlikely.

D. Ownership Requirement — The Critical Issue

The ITC is available only to the taxpayer who owns the energy property for federal income tax purposes. This ownership requirement is the central issue addressed by this memorandum. Under IRC § 46(a) and § 48(a), the energy credit is determined with respect to energy property that is part of the investment credit property placed in service by the taxpayer during the taxable year. "Investment credit property" is defined in IRC § 46(c) (as it existed prior to the IRA amendments) and § 50(a) as property to which the ITC applies, which must be (i) property with respect to which depreciation (or amortization in lieu of depreciation) is allowable, and (ii) property that has a useful life of three years or more.

The taxpayer who is entitled to claim depreciation deductions with respect to the property is generally the owner of the property for federal income tax purposes. In the case of the Saguaro Flats Solar Project, Saguaro Flats Solar LLC — a disregarded entity whose sole member is CBR — will own all of the tangible assets constituting the solar generating facility. CBR, as the sole member and the entity that reports all tax items of the disregarded entity on its own return, will be the taxpayer that claims depreciation deductions and, correspondingly, the ITC.

The key inquiry, and the impetus for this memorandum, is whether the virtual PPA / CfD structure entered into with Meridian in any way transfers beneficial ownership of the facility or its output to Meridian, creates a partnership or joint venture between Saguaro Flats Solar LLC and Meridian, or constitutes a sale-leaseback or service contract arrangement that could shift tax ownership to Meridian or create a different taxpayer. As analyzed in detail in Section IV below, the answer to each of these questions is no.

IV. Analysis of Virtual PPA / CfD Structure — Risk to ITC Qualification

A. CfD Distinguished from Physical PPA and Sale-Leaseback

The threshold question in analyzing the impact of the PPA on ITC eligibility is the proper characterization of the CfD structure for federal income tax purposes. The PPA between Saguaro Flats Solar LLC and Meridian is a virtual PPA — a financial settlement mechanism — and must be distinguished from two other contractual structures that could raise ownership and ITC concerns: (i) a physical PPA, and (ii) a sale-leaseback arrangement.

Under a physical PPA, the seller generates electricity at a dedicated facility and physically delivers that electricity to the buyer at a specified delivery point. The buyer takes title to the electricity upon delivery, schedules or nominates the output, and may in certain cases exercise operational control over the facility's dispatch. In some physical PPA structures — particularly those involving a dedicated facility built to serve a single buyer — the IRS could scrutinize whether the buyer's extensive contractual rights over the facility's output, combined with the buyer's obligation to purchase all output at a predetermined price, effectively make the buyer the economic owner of the facility for tax purposes. While this argument is generally unsuccessful where the seller retains legal title, operational control, and the risks and benefits of ownership, physical PPAs require careful structuring to ensure that the seller's tax ownership position is preserved.

Under a sale-leaseback, the owner of a facility sells the facility to a purchaser and simultaneously leases it back, retaining operational control. The ITC consequences of a sale-leaseback depend on whether the arrangement is respected as a true sale and leaseback or is recharacterized as a financing transaction. Under IRC § 48(a)(5), in the case of a sale-leaseback, the ITC may be claimed by the purchaser-lessor (who is the tax owner) rather than the seller-lessee, but only if certain conditions are met.

The CfD structure proposed for the Saguaro Flats Solar Project is fundamentally different from both of these arrangements. Under the CfD:

(a) There is no physical delivery of electricity from Seller to Buyer. Seller generates electricity and sells it into the ERCOT market on its own account. Buyer does not take title to any electricity generated by the Project.

(b) Buyer does not operate, dispatch, schedule, or control the facility or its output. Buyer has no possessory interest in the facility and no right to enter the Project site.

(c) Buyer does not bear the risk of physical performance of the facility. If the facility fails to generate electricity due to equipment malfunction, force majeure, or other cause, the CfD settlement payment is calculated based on actual metered generation (which would be zero or reduced), but the Buyer does not suffer a loss of physical energy delivery.

(d) The CfD settlement payment is calculated as the difference between a fixed Contract Price and a floating Hub Price, applied to actual metered generation. This is economically equivalent to a financial swap or hedge — it adjusts the effective price at which Seller monetizes the Project's output, but it does not transfer any property interest.

(e) Seller retains all risk and benefit of physical generation, including merchant price risk (hedged by the CfD), production risk, equipment risk, grid curtailment risk, and operational cost risk. Seller also retains all tax attributes associated with ownership, including depreciation, the ITC, and any production tax credit election that might otherwise be available.

In substance, the CfD is a financial instrument — a derivative contract — that provides price certainty to both Seller and Buyer without transferring any real or personal property interest. The CfD is economically identical to an interest rate swap or commodity swap, in which one party agrees to pay a fixed price and the other agrees to pay a floating price, with net settlement. The Commodity Futures Trading Commission ("CFTC") has recognized virtual PPAs as financial instruments subject to its jurisdiction, further supporting their characterization as derivatives rather than physical energy transactions.

For these reasons, the CfD structure does not raise the ownership concerns that could arise under a physical PPA or a sale-leaseback arrangement. Seller is and remains the sole owner of the facility, the sole entity entitled to depreciation deductions, and the sole entity entitled to claim the ITC.

B. No Partnership Risk

A potential concern in any arrangement between two parties involving a shared economic interest in a capital asset is whether the arrangement could be recharacterized as a partnership for federal income tax purposes. If the PPA were treated as creating a partnership between Saguaro Flats Solar LLC and Meridian, the partnership — not Saguaro Flats Solar LLC — would be the entity that owns the facility (or, alternatively, the partners would be treated as co-owners), and the allocation of the ITC would be governed by the partnership allocation rules under IRC § 704, which would require a separate and more complex analysis.

The IRS has addressed partnership characterization issues in the renewable energy context. Revenue Procedure 2007-65 provides a safe harbor for "flip partnerships" used in wind energy projects, under which a tax equity investor and a project sponsor form a partnership to own and operate a wind facility, with the ITC or production tax credits allocated primarily to the tax equity investor during an initial period and then "flipping" to the sponsor. The IRS issued Notice 2015-25 extending similar guidance to solar projects. These structures involve an intentional partnership formation with explicit profit-sharing and loss-sharing arrangements, capital contributions, and shared governance.

The CfD between Saguaro Flats Solar LLC and Meridian bears no resemblance to a partnership arrangement. Under the CfD:

(a) Meridian has no equity interest in Saguaro Flats Solar LLC or in any entity that owns the Project. Meridian is a contractual counterparty — a buyer under a financial derivative — not an equity investor or partner.

(b) There is no profit-sharing arrangement between the parties. Saguaro Flats Solar LLC is entitled to all profits (and bears all losses) from the operation of the facility. Meridian's only economic interest is in the CfD settlement payments, which are fixed contractual obligations independent of the facility's profitability.

(c) Meridian has no control over facility operations. Meridian does not participate in management decisions, does not approve capital expenditures, does not appoint officers or managers, and has no governance rights over Saguaro Flats Solar LLC.

(d) Meridian has no right to the ITC, to depreciation deductions, or to any other tax attribute associated with ownership of the facility. The PPA does not purport to allocate any tax benefits to Meridian.

(e) Meridian has not made and is not obligated to make any capital contribution to the Project. Meridian's sole obligation is to make (or receive) CfD settlement payments.

Under the multi-factor test for determining whether a partnership exists for federal income tax purposes — as articulated in Commissioner v. Culbertson, 337 U.S. 733 (1949), and its progeny — the parties must have joined together with the intent to carry on a business for profit, with each contributing something to the enterprise (such as money, property, or services) and sharing in the profits. None of these elements are present in the CfD arrangement. Meridian is not contributing capital, is not sharing in profits, and is not carrying on a business with Saguaro Flats Solar LLC. The CfD is an arm's-length commercial contract between unrelated parties, not a partnership or joint venture.

Recommendation: Notwithstanding the clear absence of partnership characteristics, we recommend that the PPA include express language confirming that the agreement does not create a partnership, joint venture, or association taxable as a corporation between the parties, and that each party is acting as an independent contractor in its own capacity. This language is standard in virtual PPA documentation and provides an additional layer of protection against any future recharacterization argument.

C. No Sale-Leaseback Recharacterization Risk

A sale-leaseback recharacterization could, in theory, shift tax ownership of the facility from Seller to Buyer if the IRS were to determine that the CfD structure, in substance, constitutes a sale of the facility to Meridian with a simultaneous leaseback to Saguaro Flats Solar LLC. This risk is relevant in certain physical PPA contexts where a buyer finances the construction of a dedicated facility and takes output under a long-term contract structured to resemble a financing lease. However, the CfD structure presents no sale-leaseback risk for the following reasons:

(a) The CfD does not convey any real or personal property interest to Buyer. There is no transfer of title, no conveyance of a leasehold interest, and no grant of any possessory right.

(b) Buyer has no right to possess, use, or control the facility. Buyer cannot enter the Project site, cannot direct operations, and cannot exclude others from the facility.

(c) Buyer does not bear the economic risks and benefits of ownership. Buyer does not benefit from appreciation in the facility's value, does not bear the risk of physical damage or obsolescence, and is not responsible for maintenance, repair, or replacement of equipment.

(d) The CfD creates only a financial obligation — a payment obligation that is contingent on the difference between two prices and a metered quantity. This is fundamentally different from a lease, which conveys a right to use and possess property for a specified period.

Under the factors set forth in IRS guidance and case law for distinguishing a lease from a service contract — including Revenue Ruling 55-540 and its progeny — the relevant considerations include (i) whether the purported lessee has control over the property, (ii) whether the purported lessee bears the risks and benefits of ownership, (iii) whether the purported lessee has an option to purchase the property, and (iv) whether the purported lessee has made an equity investment in the property. None of these factors point toward a lease characterization in the CfD context. The CfD is, in form and substance, a financial derivative contract, not a lease or a sale-leaseback.

Accordingly, there is no risk that the CfD would be recharacterized as a sale-leaseback arrangement, and no risk that tax ownership would be deemed transferred to Meridian under this theory.

D. No Service Contract Recharacterization

Another potential theory of recharacterization — also inapplicable here — is that the PPA constitutes a service contract under which Seller provides electricity-generation services to Buyer. If the CfD were characterized as a service contract, it could raise questions about whether Buyer is the beneficial owner of the facility under the service-contract analysis, similar to the analysis applied to certain outsourcing and managed-services arrangements.

The CfD is not a service contract because Seller is not providing electricity or any other service to Buyer. The Seller generates electricity and sells it into the ERCOT market on its own account. The Buyer is not a consumer of the electricity generated by the Project — Buyer sources its own electricity from the ERCOT market through its retail electric provider or through bilateral physical contracts. The CfD is a financial instrument that hedges Buyer's energy cost exposure to the ERCOT market, but Buyer's electricity consumption is entirely independent of the Project's generation.

This distinction is important for preserving Seller's status as the owner-operator of the facility. Under a service contract recharacterization, the IRS could argue that the Buyer is the true owner of the facility because the facility is operated for the Buyer's benefit, with the Seller acting merely as an operator or contractor. This argument fails entirely in the CfD context because (i) the facility is not operated for Buyer's benefit — it is operated for Seller's benefit, with Seller bearing all operational risk and retaining all operational control, (ii) Buyer does not consume the facility's output, (iii) Buyer does not direct or control the facility's operations, and (iv) the CfD settlement is a purely financial mechanism unrelated to the provision of any service.

E. Curtailment and Availability Provisions — Tax Ownership Implications

The PPA includes several commercial provisions that allocate economic risk between the parties, including availability guarantees and curtailment risk allocation. These provisions are currently under active negotiation between the parties and their respective counsel. We have been asked to analyze whether these provisions could have any impact on tax ownership or ITC eligibility.

Availability Guarantees. The PPA includes availability guarantee provisions under which Seller guarantees that the facility will achieve a minimum availability factor during each contract year. The parties are currently negotiating the threshold, with Meridian's initial proposal at 97.0% and Saguaro Flats Solar LLC's counterproposal at 95.0%. If the facility's actual availability falls below the guaranteed threshold, Seller is required to pay Buyer availability liquidated damages ("Availability LDs") calculated based on the shortfall between guaranteed and actual availability, multiplied by the expected generation and the Contract Price.

Availability LDs are a standard commercial feature of PPAs and do not transfer ownership or control of the facility to Buyer. Availability LDs are a form of contractual indemnification for underperformance — they compensate Buyer for the economic loss associated with lower-than-expected CfD settlement volumes. The payment of Availability LDs does not give Buyer any operational control, any right to cure the underperformance, or any interest in the facility or its assets. For tax purposes, Availability LDs are properly treated as a reduction in the effective price received by Seller under the CfD (or, alternatively, as a contractual damage payment), not as a transfer of ownership or an indication that Buyer bears the risks and benefits of ownership.

Curtailment Risk Allocation. The PPA also addresses the allocation of curtailment risk — the risk that ERCOT directs the facility to reduce output due to transmission congestion, system reliability concerns, or negative pricing. The current draft allocates curtailment risk to Seller for economic curtailment (where Seller elects to curtail because the ERCOT price is negative) and to Buyer for reliability curtailment directed by ERCOT. This allocation is a negotiated commercial term that affects the economic returns of the parties but does not transfer any ownership interest or control over the facility.

Neither the availability guarantee provisions nor the curtailment risk allocation provisions shift the benefits and burdens of ownership to Buyer. These provisions are financial risk allocation mechanisms within the CfD framework and are consistent with Seller's status as the sole owner and operator of the facility.

F. Change of Control Provisions — Tax Ownership Implications

The PPA includes change of control provisions that restrict the transfer of equity interests in Saguaro Flats Solar LLC (or in its direct or indirect parent entities) without Buyer's consent, subject to certain exceptions for (i) transfers to affiliates, (ii) transfers in connection with a tax equity financing, and (iii) transfers after the expiration of a specified lock-up period. These provisions are commercial in nature and are designed to protect Buyer's interest in the creditworthiness and operational capability of the Seller counterparty.

While the change of control provisions do not, in themselves, affect ITC eligibility, they intersect with an important tax consideration: the ITC recapture rules under IRC § 50(a).

Under IRC § 50(a)(1), if investment credit property (including energy property eligible for the ITC) is disposed of, or otherwise ceases to be investment credit property, before the close of the recapture period, the taxpayer must recapture a portion of the ITC previously claimed. The recapture amount decreases ratably over the five-year recapture period at a rate of 20% per year. That is:

• Disposition in Year 1: 100% recapture

• Disposition in Year 2: 80% recapture

• Disposition in Year 3: 60% recapture

• Disposition in Year 4: 40% recapture

• Disposition in Year 5: 20% recapture

• After Year 5: No recapture

For the Saguaro Flats Solar Project, the recapture period runs for five years from the placed-in-service date — approximately April 1, 2027 through March 31, 2032. During this period, any "disposition" of the facility — or any event that causes the facility to "cease to be investment credit property" — could trigger recapture of a portion of the $42,750,000 ITC.

The question of what constitutes a "disposition" for purposes of IRC § 50(a) is fact-specific. A sale of the physical assets of the facility clearly constitutes a disposition. A sale of 100% of the membership interests in Saguaro Flats Solar LLC (the disregarded entity that owns the facility) would also likely be treated as a disposition, because the sale of a disregarded entity's membership interests is treated as a sale of the underlying assets for federal income tax purposes under Treasury Regulation § 301.7701-3. However, a change of control at the CBR parent level — for example, a sale by Ridgepoint Capital Partners LP of its 68% equity interest in CBR — should not constitute a disposition of the energy property, because CBR (a corporation treated as a separate taxable entity) continues to own Saguaro Flats Solar LLC, which continues to own the facility. The "disposition" is of CBR equity, not of the energy property.

Nevertheless, the recapture risk associated with changes of control during the five-year window should be carefully managed. We recommend the following:

(a) The PPA and the organizational documents of Saguaro Flats Solar LLC should include language prohibiting any direct sale, assignment, or transfer of the energy property (i.e., the physical assets of the solar facility) or of the membership interests in Saguaro Flats Solar LLC during the five-year recapture period, except with the prior written consent of CBR's tax advisor and upon a determination that the proposed transfer would not trigger recapture.

(b) If the PPA's change of control provisions permit transfers during the recapture period, those provisions should include a condition that any permitted transferee must assume the obligation to maintain the facility as investment credit property and to refrain from any action that would trigger recapture.

(c) CBR should coordinate any Ridgepoint exit strategy (including a potential secondary sale of Ridgepoint's 68% interest in CBR) to ensure that the exit transaction is structured in a manner that does not trigger ITC recapture. A sale of Ridgepoint's interest in CBR should not trigger recapture, as discussed above, but the transaction should be reviewed by tax counsel before execution.

(d) The Credit Facility documents should include a corresponding ITC recapture protection covenant, and we understand from discussions with Helen Nakamura that the lender group's term sheet already contemplates such a covenant.

V. Prevailing Wage and Apprenticeship Requirements

To qualify for the 30% ITC rate — rather than the 6% base rate — the Saguaro Flats Solar Project must satisfy the prevailing wage and apprenticeship requirements enacted by the Inflation Reduction Act under IRC § 48(a)(10) and (11), as further implemented by Treasury and IRS guidance, including Notice 2022-61 (initial guidance on prevailing wage and apprenticeship requirements), proposed regulations under 29 CFR Part 5 (Department of Labor wage determinations), and subsequent notices and regulations.

Prevailing Wage Requirement. Under IRC § 48(a)(10)(A), the prevailing wage requirement is satisfied if, during the construction of the facility and during the five-year period beginning on the date the facility is placed in service (the "alteration or repair period"), any laborers and mechanics employed by the taxpayer or any contractor or subcontractor in the construction, alteration, or repair of the facility are paid wages at rates not less than the prevailing rates for construction, alteration, or repair of a similar character in the locality in which the facility is located, as determined by the Secretary of Labor in accordance with subchapter IV of chapter 31 of title 40, United States Code (the Davis-Bacon Act). The applicable prevailing wage rates for Pecos County, Texas are published by the Department of Labor and updated periodically.

For the construction period, this means that all laborers and mechanics employed by Sunbelt Power Construction LLC (as the EPC contractor) and all subcontractors performing work on the facility must be paid at or above the applicable Davis-Bacon prevailing wage rates for each craft classification. For the alteration or repair period (the five years following placed-in-service), this means that any alteration or repair work performed on the facility — including major maintenance, component replacements, and capital improvements — must also be performed at prevailing wage rates.

The IRA provides a correction mechanism under IRC § 48(a)(10)(B) that allows a taxpayer to cure prevailing wage violations by (i) making back payments to affected workers, plus interest, and (ii) paying a penalty to the IRS of $5,000 per worker per violation (or $10,000 for intentional disregard). While this correction mechanism provides a safety valve, it is preferable to ensure full compliance from the outset.

Apprenticeship Requirement. Under IRC § 48(a)(11), the apprenticeship requirement is satisfied if (i) the applicable percentage of total labor hours for the construction, alteration, or repair of the facility is performed by qualified apprentices, and (ii) the taxpayer and any contractor or subcontractor make a good faith effort to request qualified apprentices from registered apprenticeship programs. The applicable percentage is 12.5% for facilities that begin construction in 2024 and increases to 15% for facilities that begin construction in 2025 or later. Since the Saguaro Flats Solar Project is expected to begin construction in late 2025, the applicable apprenticeship percentage is 15%.

A "qualified apprentice" is an employee who is participating in a registered apprenticeship program that is registered under the Act of August 16, 1937 (commonly known as the National Apprenticeship Act), as amended. The apprenticeship requirement includes a good faith exception — if the taxpayer or contractor requests qualified apprentices from one or more registered programs and the request is denied or not responded to within five business days, the requirement is deemed satisfied for the labor hours that would otherwise need to be performed by apprentices.

EPC Contract Review. CBR must ensure that the EPC Contract with Sunbelt Power Construction LLC includes adequate prevailing wage compliance provisions and apprenticeship requirements, with appropriate flow-down obligations to all subcontractors. We have reviewed the executed EPC Contract and note the following:

(a) Section 14.3 of the EPC Contract includes a general provision requiring Sunbelt to comply with "all applicable federal, state, and local labor laws and regulations," but does not specifically reference the Davis-Bacon Act, the prevailing wage requirements of IRC § 48(a)(10), or the apprenticeship requirements of IRC § 48(a)(11).

(b) The EPC Contract does not include a specific prevailing wage compliance schedule or wage rate exhibit, nor does it include recordkeeping obligations specifically tied to the IRA prevailing wage and apprenticeship requirements.

(c) The EPC Contract does not include an indemnification provision specifically addressing the risk of ITC reduction resulting from Sunbelt's failure to comply with prevailing wage or apprenticeship requirements.

Recommendation: We recommend that the EPC Contract be amended to include (i) an express obligation for Sunbelt and all subcontractors to comply with the prevailing wage requirements of IRC § 48(a)(10) and the apprenticeship requirements of IRC § 48(a)(11), (ii) a prevailing wage schedule or exhibit incorporating the applicable Davis-Bacon rates for Pecos County, Texas, (iii) detailed recordkeeping obligations requiring Sunbelt to maintain certified payroll records and apprenticeship documentation for the duration of the statute of limitations applicable to CBR's ITC claim, and (iv) an indemnification provision under which Sunbelt agrees to indemnify CBR for any ITC reduction, recapture, or penalty resulting from Sunbelt's failure to comply with prevailing wage or apprenticeship requirements. We are prepared to draft these amendments for the EPC Contract and recommend that they be circulated to Sunbelt's counsel (Morgan & Lyle PLLC, attention Chris Devereaux) promptly.

VI. Drafting Recommendations for the PPA

Based on the analysis set forth in Sections III through V above, we recommend that the following provisions be incorporated into the Seller's Revised Draft PPA (Second Draft), targeted for circulation to Meridian's counsel (Hargreaves Winston LLP, attention Jennifer Aldric) on August 11, 2025. These provisions are designed to preserve Seller's tax ownership position, prevent recharacterization of the CfD, and protect the ITC.

A. Tax Ownership Preservation Language

The PPA should include an express provision, located in the representations and covenants article (or in a standalone tax article), confirming that Seller (Saguaro Flats Solar LLC) is and shall remain the sole owner of the facility for all purposes, including for federal, state, and local income tax purposes. The provision should state unambiguously that nothing in the PPA is intended to, or shall be construed to, (i) transfer any ownership interest in the facility, or any portion thereof, to Buyer, (ii) create any lien, security interest, or encumbrance on the facility in favor of Buyer (other than any contractual rights under the PPA itself), or (iii) transfer, assign, or convey any tax benefits, tax attributes, or tax credits associated with the facility — including, without limitation, the investment tax credit under IRC § 48, depreciation deductions under IRC § 167 or § 168, or any other tax attribute — to Buyer.

This provision serves both a substantive and a prophylactic purpose. Substantively, it confirms the parties' shared intent that the CfD is a financial arrangement and that Seller retains all indicia of ownership. Prophylactically, it provides the IRS and any reviewing court with clear evidence of the parties' intent, which is a relevant (though not dispositive) factor in characterization disputes.

B. No-Partnership / No-Joint-Venture Clause

The PPA should include a provision stating that the PPA does not create and shall not be deemed to create a partnership, joint venture, agency relationship, fiduciary relationship, or association taxable as a corporation between the parties for any purpose, including for federal, state, or local income tax purposes. The provision should further confirm that each party is acting solely as an independent contractor in its own capacity and for its own account, and that neither party has the authority to bind the other or to act as the other's agent.

This provision is standard in virtual PPA documentation and is consistent with similar language found in ISDA Master Agreements and Edison Electric Institute form agreements. While the absence of a no-partnership clause would not, in itself, create a partnership (the existence of a partnership is determined under federal law based on the objective characteristics of the arrangement, not the parties' labeling), the inclusion of this clause is prudent and supports the parties' position in any future inquiry.

C. ITC Recapture Protection

The PPA should include a covenant, binding on Seller, that Seller shall not take any action — or fail to take any action — that would cause the facility to cease to be "investment credit property" within the meaning of IRC § 50(a) during the recapture period (the five-year period beginning on the placed-in-service date). Specifically, Seller should covenant that it will not, during the recapture period, (i) sell, transfer, or otherwise dispose of the facility or any material portion thereof (other than replacement of worn or damaged components in the ordinary course of maintenance), (ii) convert the facility to a use that does not qualify as energy property under IRC § 48, or (iii) take any other action that would trigger ITC recapture.

If the change of control article of the PPA permits transfers of equity interests in Saguaro Flats Solar LLC during the recapture period, the PPA should include a condition precedent to any such transfer requiring that any permitted transferee execute a written assumption agreement, in form and substance reasonably satisfactory to Buyer, pursuant to which the transferee assumes the obligation to maintain the facility as investment credit property and to refrain from any action that would trigger ITC recapture. This protects Buyer's interest in the continued operation of the facility as a CfD settlement reference asset.

Additionally, the PPA should include a representation by Seller that it intends to claim the ITC with respect to the facility and will not voluntarily elect out of the ITC under IRC § 48 or elect the production tax credit under IRC § 45 in lieu of the ITC, without Buyer's prior written consent (which may be withheld in Buyer's sole discretion). While this representation primarily protects Seller's own economic interest, it also provides Buyer with assurance that the Project's financial model — which underpins the Contract Price — is based on the ITC assumption.

D. Characterization of CfD Payments

The PPA should define the CfD settlement payments with precision and in a manner that supports the financial derivative characterization. Specifically, the PPA should state that all settlement payments made under the PPA are payments under a "contract for differences" or "financial settlement contract," and are not payments for the purchase or sale of electricity, capacity, ancillary services, or renewable energy certificates. The PPA should further state that the parties intend the CfD to be treated as a financial hedge or swap for all purposes, including for federal income tax, regulatory, and accounting purposes.

This characterization language is important for several reasons beyond the ITC analysis, including (i) regulatory compliance (a financial CfD is generally not subject to state public utility regulation, whereas a physical power sale may be), (ii) accounting treatment (a CfD may qualify for derivative accounting under ASC 815, whereas a physical PPA may require different treatment), and (iii) bankruptcy treatment (a financial CfD may qualify as a "swap agreement" under the Bankruptcy Code, providing certain safe harbor protections for non-defaulting counterparties). For ITC purposes, the characterization language reinforces the conclusion that the CfD does not transfer any property interest or create any arrangement inconsistent with Seller's tax ownership.

E. Indemnification for Tax Consequences

We recommend that the PPA include a mutual indemnification provision addressing the risk of adverse tax consequences arising from a recharacterization of the PPA by a taxing authority. Specifically:

(a) If the IRS or any other taxing authority recharacterizes the CfD as creating a partnership, joint venture, sale-leaseback, service contract, or other arrangement that adversely affects Seller's ability to claim the ITC or any other tax benefit associated with ownership of the facility, and such recharacterization is attributable to the actions or omissions of Buyer (including Buyer's filing positions or public statements inconsistent with the CfD characterization), Buyer should indemnify Seller for all resulting losses, including the value of any lost or recaptured ITC, additional taxes, interest, and penalties.

(b) Conversely, if Seller's actions or omissions cause a recharacterization that adversely affects Buyer's tax position (for example, if the IRS were to treat the CfD settlement payments as something other than ordinary income or loss to Buyer), Seller should indemnify Buyer for all

PRIVILEGED AND CONFIDENTIAL — ATTORNEY-CLIENT COMMUNICATION / ATTORNEY WORK PRODUCT
MEMORANDUM
TO: Patricia Dunmore, Responsible Partner, Energy & Infrastructure Brett Callahan, Lead Associate, Energy & Infrastructure
FROM: Samuel Reeves, Associate, Tax
DATE: July 18, 2025
RE: Saguaro Flats Solar Project — ITC Eligibility Under IRC § 48 and Impact of Virtual PPA / CfD Structure on Tax Credit Qualification
MATTER NO.: 1015-00002
CLIENT: Calloway-Briggs Renewables Inc.
I. Executive Summary
Calderwood & Harkness LLP represents Calloway-Briggs Renewables Inc. ("CBR") in connection with the negotiation of a twenty-year virtual power purchase agreement (the "PPA") with Meridian DataCore Solutions Inc. ("Meridian" or "Buyer") for the output of the Saguaro Flats Solar Project (the "Project"), a 150 MWac (195 MWdc) ground-mounted single-axis tracking solar photovoltaic facility to be developed, constructed, and operated on an approximately 1,400-acre site in Pecos County, Texas. The PPA is structured as a contract for differences ("CfD") settling at the ERCOT West Hub. It is not a physical power sale. Under the CfD, Buyer pays Seller the Contract Price ($20.00/MWh, fixed for years one through five, escalating at 1.50% per annum compounding in years six through twenty) for each MWh generated, with net settlement against the ERCOT West Hub spot price.
The Project will be owned by Saguaro Flats Solar LLC, a Delaware limited liability company wholly owned by CBR. Saguaro Flats Solar LLC is the contractual Seller under the PPA and will own all tangible and intangible assets associated with the Project, including modules, inverters, trackers, balance-of-system equipment, the interconnection facilities on the Seller's side of the point of interconnection, and all environmental attributes and renewable energy certificates generated by the facility.
This memorandum has been prepared at the request of the Energy & Infrastructure practice group to analyze whether the Saguaro Flats Solar Project qualifies for the Investment Tax Credit ("ITC") under Section 48 of the Internal Revenue Code of 1986, as amended (the "Code" or "IRC"), at the full 30% rate (assuming satisfaction of prevailing wage and apprenticeship requirements), the estimated dollar value of the ITC based on the current engineering, procurement, and construction ("EPC") contract price, and — most critically — whether the virtual PPA / CfD structure creates any risk to ITC qualification. The estimated ITC value, based on a $142,500,000 fixed-price turnkey EPC contract with Sunbelt Power Construction LLC ("Sunbelt"), is approximately $42,750,000, a figure that is central to the Project's economics and to the lender group's underwriting of the $108,000,000 senior secured construction-to-term loan facility being arranged by Tralvendo National Bank, N.A. ("Tralvendo").
Conclusion. Based on the analysis set forth below, it is our opinion that the CfD structure does not jeopardize ITC eligibility. Saguaro Flats Solar LLC will retain tax ownership of the facility and will be the proper taxpayer to claim the ITC, provided that (a) certain PPA language is included to preserve Seller's ownership position and to preclude recharacterization arguments, (b) the Project satisfies all statutory and regulatory requirements for the ITC, including the prevailing wage and apprenticeship requirements enacted by the Inflation Reduction Act of 2022 (the "IRA"), and (c) no transfer or disposition occurs during the five-year recapture period under IRC § 50(a) that would cause the facility to cease to be investment credit property. Specific drafting recommendations are set forth in Section VI below, and we recommend that they be incorporated into the Seller's Revised Draft PPA (Second Draft), which is targeted for circulation to Meridian's counsel on August 11, 2025.
II. Background — Project and Transaction Structure
A. Project Overview
The Saguaro Flats Solar Project is a utility-scale ground-mounted solar photovoltaic generation facility with a nameplate direct current ("DC") capacity of 195 MWdc and an alternating current ("AC") capacity of 150 MWac, yielding a DC-to-AC ratio of approximately 1.30. The facility will employ single-axis tracking technology, which is expected to optimize energy production by adjusting the angle of the photovoltaic modules to follow the sun's east-to-west path throughout the day. This technology is industry-standard for utility-scale solar installations in West Texas and is well-suited to the high direct normal irradiance characteristic of the Project site.
The Project is located on approximately 1,400 acres situated along FM Road 1776, approximately twelve miles southeast of Fort Stockton, Pecos County, Texas 79735. The site is leased from Redrock Mesa Ranch LP ("Redrock") under a thirty-five-year ground lease (the "Ground Lease"), with two ten-year extension options exercisable at Saguaro Flats Solar LLC's discretion. The Ground Lease was executed on March 22, 2025 and provides for annual rent escalating at 1.25% per annum, with a one-time construction disturbance payment due at the commencement of civil works.
Sunbelt Power Construction LLC, an established solar EPC contractor based in Austin, Texas, has been engaged as the Project's EPC contractor under a fixed-price turnkey EPC contract (the "EPC Contract") with a contract value of $142,500,000. The EPC Contract scope includes engineering and design, procurement of all major equipment (modules, inverters, single-axis trackers, racking, transformer, and balance-of-system components), civil works and site preparation, installation and commissioning, and performance testing. The EPC Contract was executed on June 1, 2025, and Sunbelt has issued a notice to proceed, with mobilization expected to commence in the fourth quarter of 2025.
Total estimated project cost is approximately $154,300,000, which includes the EPC contract value of $142,500,000 plus approximately $11,800,000 in soft costs, including land acquisition and lease costs, permitting fees, environmental and cultural resource assessments, interconnection costs, development-stage legal and advisory fees, insurance premiums, contingency reserves, and financing costs during the construction period.
The expected commercial operation date ("COD") is April 1, 2027, consistent with the milestone schedule set forth in the EPC Contract and the construction loan drawdown schedule. Achievement of COD under the PPA requires, among other things, (i) completion of construction and commissioning, (ii) successful completion of the performance test demonstrating the facility's ability to generate electricity at or above the guaranteed minimum capacity, (iii) interconnection to ERCOT and receipt of all required approvals and certifications from ERCOT, and (iv) execution of all required revenue metering agreements.
The Project will interconnect to the ERCOT grid at the Ft. Stockton 345 kV Substation via transmission facilities owned and operated by West Texas Wires LLC. A Large Generator Interconnection Agreement ("LGIA") was executed on May 15, 2025 (ERCOT Queue Position ERCOT-GI-2024-0437), and the interconnection study process has been completed. The estimated interconnection cost, which is included in the $11,800,000 soft cost budget, is approximately $4,200,000, consisting primarily of network upgrade costs and the Seller's share of substation expansion costs.
An independent solar resource assessment was performed by Heliograph Energy Consulting LLC ("Heliograph"), a nationally recognized solar resource consultancy, utilizing on-site pyranometer data collected over a fourteen-month measurement campaign (January 2024 through February 2025), satellite-derived irradiance data, and industry-standard modeling software. Heliograph's assessment concluded that the Project's P50 annual net generation (after accounting for soiling, module degradation, electrical losses, availability, and curtailment assumptions) is approximately 350,000 MWh per year, with a P90 estimate of approximately 315,000 MWh per year.
B. Ownership Structure
Saguaro Flats Solar LLC is a Delaware limited liability company (EIN 93-1284506) formed on January 10, 2025, for the sole purpose of developing, constructing, owning, and operating the Project. Saguaro Flats Solar LLC is 100% owned by CBR (Delaware corporation, EIN 82-4637201) and is treated as a disregarded entity for federal income tax purposes. As a disregarded entity, all items of income, deduction, gain, loss, and credit attributable to Saguaro Flats Solar LLC — including the ITC — flow through to CBR as the sole member. CBR will accordingly be the taxpayer that claims the ITC on its federal income tax return for the taxable year in which the Project is placed in service.
CBR is a Delaware corporation managed by its officers and board of directors. Lena Calloway-Briggs serves as CBR's Chief Executive Officer. The majority equity interest in CBR — approximately 68% of CBR's common equity — is held by Ridgepoint Capital Partners LP ("Ridgepoint"), a private equity fund managed by its general partner, Ridgepoint Capital Management LLC (Managing Partner: Alan Driscoll). The remaining approximately 32% of CBR's common equity is held by Lena Calloway-Briggs (18%), other members of CBR management (9%), and certain individual investors (5%). Ridgepoint's investment was made through a Series A preferred equity round closed in September 2023.
Saguaro Flats Solar LLC is the project company and will own all Project assets, including the solar photovoltaic generating equipment, balance-of-system components, the leasehold interest in the Project site under the Ground Lease, interconnection rights, permits and approvals, environmental attributes and renewable energy certificates, and all contractual rights, including its rights as Seller under the PPA. Saguaro Flats Solar LLC will be the counterparty Seller under the PPA with Meridian and will also be the borrower under the senior secured construction-to-term loan facility.
C. PPA Structure — Virtual PPA / Contract for Differences
The PPA between Saguaro Flats Solar LLC (as Seller) and Meridian DataCore Solutions Inc. (as Buyer) is structured as a virtual power purchase agreement, also commonly referred to in the industry as a "synthetic PPA" or "financial PPA." The economic substance of the PPA is a contract for differences — a bilateral financial settlement mechanism under which the parties settle the difference between a fixed contract price and a floating market price. The PPA term is twenty years, commencing on COD (expected April 1, 2027) and expiring on March 31, 2047.
The aggregate nominal contract value of the PPA over its twenty-year term is estimated at approximately $140,000,000, based on P50 annual generation of 350,000 MWh and the contract price escalation schedule. The contract price is structured as follows:
• Years 1 through 5 (April 1, 2027 – March 31, 2032): $20.00 per MWh (fixed)
• Years 6 through 20 (April 1, 2032 – March 31, 2047): $20.00 per MWh base, escalating at 1.50% per annum compounding (Year 6: $20.30/MWh; Year 10: $21.53/MWh; Year 15: $23.20/MWh; Year 20: approximately $25.02/MWh)
The settlement hub is the ERCOT West Hub, a liquid, transparent pricing node within the Electric Reliability Council of Texas market. The CfD settlement mechanics operate as follows:
(a) For each settlement period (expected to be monthly), the total MWh of electricity actually generated by the Project and metered at the revenue meter is determined (the "Delivered Quantity").
(b) The Seller receives the ERCOT West Hub spot price for each MWh generated by selling the electricity into the ERCOT real-time or day-ahead market. Seller retains all merchant revenue from ERCOT market sales.
(c) The CfD net settlement payment is calculated as follows: if the Contract Price exceeds the Hub Price for the applicable settlement period, the Buyer pays to Seller an amount equal to (Contract Price minus Hub Price) multiplied by the Delivered Quantity. If the Hub Price exceeds the Contract Price, Seller pays to Buyer an amount equal to (Hub Price minus Contract Price) multiplied by the Delivered Quantity.
(d) The net effect is that, in all market conditions, Seller's effective realized price per MWh for each settlement period equals the Contract Price — Seller receives the Hub Price from ERCOT market sales plus (or minus) the CfD settlement payment.
Critically, there is no physical delivery of electricity from Seller to Buyer under the PPA. Buyer does not take title to, or possession of, any electricity generated by the Project. Buyer does not schedule, dispatch, or nominate the Project's output. Buyer has no right to direct the operation of the facility. Settlement is purely financial — it is a payment obligation based on the difference between two prices applied to a metered quantity. In this respect, the PPA functions as a financial hedge or swap instrument, notwithstanding that it is documented as a power purchase agreement for commercial and counterparty credit purposes.
The expected contracted volume at P50 is approximately 7,000,000 MWh over the twenty-year PPA term (350,000 MWh per year multiplied by 20 years). Environmental attributes and renewable energy certificates ("RECs") associated with the Project's generation are addressed separately in the PPA; under the current draft, Buyer will receive all RECs generated by the Project, but the transfer of RECs is structured as a separate sale and does not affect the characterization of the CfD settlement mechanism or the tax ownership analysis.
D. Project Financing
The Project is being financed with a combination of equity and senior secured debt. Tralvendo National Bank, N.A. is serving as the Administrative Agent, Lead Arranger, and Bookrunner for a $108,000,000 senior secured construction-to-term loan facility (the "Credit Facility"). The Credit Facility is structured as a single-draw construction facility converting to a fully amortizing term loan upon achievement of COD and satisfaction of conversion conditions.
The syndicate of lenders participating in the Credit Facility is as follows:
The debt-to-equity ratio is approximately 70/30, with an equity contribution from CBR of approximately $46,300,000, sourced primarily from Ridgepoint's committed capital and CBR's retained earnings from its existing operating solar portfolio.
The interest rate on the Credit Facility is Term SOFR plus 175 basis points during the term loan period and Term SOFR plus 200 basis points during the construction period. The minimum debt service coverage ratio ("DSCR") covenant is 1.30x, and the Project is projected to achieve a DSCR of approximately 1.35x at P50 generation and Year 1 pricing, providing adequate cushion above the covenant threshold. The Credit Facility maturity is expected to be eighteen years from COD, with a sculpted amortization schedule tied to the Project's expected cash flows under the PPA.
Lender's counsel for the Credit Facility is Whitfield Stroval & Cade LLP, with Philip Thornton serving as lead partner. Whitfield Stroval will conduct its own legal due diligence on the PPA, the EPC Contract, the Ground Lease, the LGIA, and other material project documents, and will provide a lender's opinion in connection with the closing of the Credit Facility.
The ITC value is a critical component of the Project's economics and the lender group's underwriting. The approximately $42,750,000 ITC reduces CBR's federal income tax liability in the year the Project is placed in service (expected to be the 2027 taxable year), freeing cash that supports the equity return on the Project and provides a significant margin of safety in the financial model. The lender group's independent financial model review, performed by Llewellyn Capital Advisors LLC, incorporates the ITC at the 30% rate as a base case assumption. Any reduction in or loss of the ITC would materially impair the Project's financial viability and could result in a default under the Credit Facility.
III. ITC Eligibility Analysis Under IRC § 48
A. Statutory Framework
Section 48 of the Internal Revenue Code provides an investment tax credit for certain "energy property" placed in service by the taxpayer during the taxable year. The ITC is a dollar-for-dollar reduction in the taxpayer's federal income tax liability, calculated as a percentage of the eligible basis of the energy property. The ITC has been a cornerstone of federal policy supporting the development of renewable energy generating facilities for decades, and the credit mechanism has been extended and modified several times by Congress, most recently by the Inflation Reduction Act of 2022 (Pub. L. 117-169, enacted August 16, 2022).
Solar electric generating equipment is specifically enumerated as a category of energy property eligible for the ITC under IRC § 48(a)(3)(A)(i). This includes equipment that uses solar energy to generate electricity, including photovoltaic modules, inverters, transformers, racking and mounting systems, single-axis and dual-axis tracking systems, wiring, combiner boxes, switchgear, monitoring equipment, and related balance-of-system components that are integral to the generation of electricity from solar energy. The ITC for solar energy property has historically been the most widely utilized tax credit in the renewable energy sector.
The Inflation Reduction Act of 2022 made several significant modifications to the ITC framework for solar facilities. Most notably, the IRA established a two-tier credit rate structure: a base rate of 6%, and an increased rate of 30% available to projects that satisfy prevailing wage and apprenticeship requirements during construction and, in the case of the ITC, during the five-year recapture period for alteration and repair work. The IRA also introduced bonus credit adders for domestic content (an additional 10 percentage points) and location in an energy community (an additional 10 percentage points), potentially increasing the ITC rate to as high as 50% (or 70% in certain circumstances involving low-income community allocations, which are not applicable to the Project). The IRA extended the ITC for solar facilities through at least 2032, with a phase-down mechanism tied to greenhouse gas emissions reduction targets, and established alternative beginning-of-construction safe harbors.
For purposes of this memorandum, we assume that the Project will satisfy the prevailing wage and apprenticeship requirements and will qualify for the 30% ITC rate. The analysis of prevailing wage and apprenticeship compliance is addressed separately in Section V. We do not assume any bonus adders (energy community or domestic content) in our base ITC estimate; potential adders are discussed in Section VII.
B. Eligible Basis
The ITC is computed as a percentage of the taxpayer's "basis" in the energy property, as determined under the general basis rules of the Code. The eligible basis generally includes the cost of tangible personal property and other tangible property (not including a building or its structural components) that is used as an integral part of the solar generating facility. Under IRC § 48(a)(1), the amount of the energy credit for any taxable year is the energy percentage of the basis of each energy property placed in service during such taxable year.
The EPC contract price with Sunbelt Power Construction LLC is $142,500,000 on a fixed-price, turnkey basis. This contract price encompasses the design, engineering, procurement, construction, commissioning, and performance testing of the complete solar generating facility, including all major equipment (photovoltaic modules, string inverters, single-axis tracker systems, racking, medium-voltage collection system, project substation and step-up transformer, SCADA and monitoring systems), civil and structural works (grading, roads, drainage, fencing, foundations, pile driving), and electrical balance-of-system (AC and DC wiring, combiner boxes, switchgear, grounding systems). Based on our preliminary review, substantially all of the costs included in the EPC contract price relate to tangible personal property or other tangible property integral to the solar generating facility and are expected to qualify for inclusion in the eligible basis for ITC purposes.
The estimated ITC at the 30% rate is therefore:
30% × $142,500,000 = $42,750,000
This estimate is preliminary and is based on the assumption that substantially all EPC costs are includable in eligible basis. The eligible basis will need to be confirmed through a detailed cost segregation analysis, which should be performed by Aldgate & Pryor CPAs LLP (CBR's independent auditor) or a specialized engineering-based cost segregation firm. Certain cost categories within the EPC contract may require closer scrutiny, including:
(a) Site preparation costs — costs for grading, clearing, and drainage that are integral to the installation and operation of the solar facility are generally includable in basis, but costs attributable to general land improvements (e.g., roads primarily serving non-facility purposes) may not qualify;
(b) Interconnection costs — costs for electrical facilities on the Seller's side of the point of interconnection are generally includable, but costs for network upgrades owned by the transmission provider may not be;
(c) Fencing and security systems — fencing integral to the facility's operation and required by code or safety standards is generally includable;
(d) Commissioning and testing costs — these costs are generally includable as part of the cost of placing the energy property in service.
It is also important to note that the eligible basis does not include the cost of land or the leasehold interest in the Project site under the Ground Lease, nor does it include non-integral soft costs such as development-stage legal fees, financing costs, permitting fees, or insurance premiums incurred prior to the commencement of construction, to the extent such costs are not capitalized into the basis of the energy property under applicable tax accounting rules. The approximately $11,800,000 in soft costs included in the $154,300,000 total project cost is therefore excluded from our preliminary ITC calculation, although a portion of such costs (particularly interconnection costs) may ultimately be includable following the cost segregation study.
C. Placed-in-Service Requirement
The ITC is claimed in the taxable year in which the energy property is "placed in service." The placed-in-service date is a critical milestone for ITC purposes, as it determines (i) the year in which the credit is available, (ii) the commencement of the five-year recapture period under IRC § 50(a), and (iii) the beginning of the Modified Accelerated Cost Recovery System ("MACRS") depreciation period for the facility (the solar facility qualifies for five-year MACRS depreciation under IRC § 168, with 100% bonus depreciation available for projects placed in service before January 1, 2027, or potentially later depending on legislative developments).
Under Treasury Regulation § 1.46-3(d), property is considered "placed in service" in the earlier of (i) the taxable year in which the period for depreciation begins, or (ii) the taxable year in which the property is placed in a condition or state of readiness and availability for a specifically assigned function, whether in a trade or business, in the production of income, in a tax-exempt activity, or in a personal activity. For a solar generating facility, this generally means the date on which the facility is interconnected to the grid, has completed commissioning and performance testing, and is capable of generating and delivering electricity in commercial quantities.
The expected COD under the PPA is April 1, 2027. Achievement of COD under the PPA requires satisfaction of several conditions, including: (i) mechanical completion of the facility, (ii) interconnection to ERCOT and energization of the facility, (iii) successful completion of the performance test specified in the EPC Contract, (iv) receipt of all required governmental approvals and permits for commercial operation, and (v) execution of all metering and settlement agreements with ERCOT. These conditions are consistent with, and should satisfy, the placed-in-service standard under Treasury Regulation § 1.46-3(d). Assuming COD is achieved on April 1, 2027, the Project will be placed in service for ITC purposes in CBR's 2027 taxable year (CBR files on a calendar-year basis), and the ITC will be claimed on CBR's 2027 federal income tax return.
We note that if COD is delayed beyond December 31, 2027, the placed-in-service date would shift to the 2028 taxable year, which would defer the ITC claim by one year. The EPC Contract includes schedule guarantees and delay liquidated damages to mitigate this risk, and the current construction schedule includes approximately four months of schedule contingency. Based on our discussions with the project management team, a delay beyond December 31, 2027 is considered unlikely.
D. Ownership Requirement — The Critical Issue
The ITC is available only to the taxpayer who owns the energy property for federal income tax purposes. This ownership requirement is the central issue addressed by this memorandum. Under IRC § 46(a) and § 48(a), the energy credit is determined with respect to energy property that is part of the investment credit property placed in service by the taxpayer during the taxable year. "Investment credit property" is defined in IRC § 46(c) (as it existed prior to the IRA amendments) and § 50(a) as property to which the ITC applies, which must be (i) property with respect to which depreciation (or amortization in lieu of depreciation) is allowable, and (ii) property that has a useful life of three years or more.
The taxpayer who is entitled to claim depreciation deductions with respect to the property is generally the owner of the property for federal income tax purposes. In the case of the Saguaro Flats Solar Project, Saguaro Flats Solar LLC — a disregarded entity whose sole member is CBR — will own all of the tangible assets constituting the solar generating facility. CBR, as the sole member and the entity that reports all tax items of the disregarded entity on its own return, will be the taxpayer that claims depreciation deductions and, correspondingly, the ITC.
The key inquiry, and the impetus for this memorandum, is whether the virtual PPA / CfD structure entered into with Meridian in any way transfers beneficial ownership of the facility or its output to Meridian, creates a partnership or joint venture between Saguaro Flats Solar LLC and Meridian, or constitutes a sale-leaseback or service contract arrangement that could shift tax ownership to Meridian or create a different taxpayer. As analyzed in detail in Section IV below, the answer to each of these questions is no.
IV. Analysis of Virtual PPA / CfD Structure — Risk to ITC Qualification
A. CfD Distinguished from Physical PPA and Sale-Leaseback
The threshold question in analyzing the impact of the PPA on ITC eligibility is the proper characterization of the CfD structure for federal income tax purposes. The PPA between Saguaro Flats Solar LLC and Meridian is a virtual PPA — a financial settlement mechanism — and must be distinguished from two other contractual structures that could raise ownership and ITC concerns: (i) a physical PPA, and (ii) a sale-leaseback arrangement.
Under a physical PPA, the seller generates electricity at a dedicated facility and physically delivers that electricity to the buyer at a specified delivery point. The buyer takes title to the electricity upon delivery, schedules or nominates the output, and may in certain cases exercise operational control over the facility's dispatch. In some physical PPA structures — particularly those involving a dedicated facility built to serve a single buyer — the IRS could scrutinize whether the buyer's extensive contractual rights over the facility's output, combined with the buyer's obligation to purchase all output at a predetermined price, effectively make the buyer the economic owner of the facility for tax purposes. While this argument is generally unsuccessful where the seller retains legal title, operational control, and the risks and benefits of ownership, physical PPAs require careful structuring to ensure that the seller's tax ownership position is preserved.
Under a sale-leaseback, the owner of a facility sells the facility to a purchaser and simultaneously leases it back, retaining operational control. The ITC consequences of a sale-leaseback depend on whether the arrangement is respected as a true sale and leaseback or is recharacterized as a financing transaction. Under IRC § 48(a)(5), in the case of a sale-leaseback, the ITC may be claimed by the purchaser-lessor (who is the tax owner) rather than the seller-lessee, but only if certain conditions are met.
The CfD structure proposed for the Saguaro Flats Solar Project is fundamentally different from both of these arrangements. Under the CfD:
(a) There is no physical delivery of electricity from Seller to Buyer. Seller generates electricity and sells it into the ERCOT market on its own account. Buyer does not take title to any electricity generated by the Project.
(b) Buyer does not operate, dispatch, schedule, or control the facility or its output. Buyer has no possessory interest in the facility and no right to enter the Project site.
(c) Buyer does not bear the risk of physical performance of the facility. If the facility fails to generate electricity due to equipment malfunction, force majeure, or other cause, the CfD settlement payment is calculated based on actual metered generation (which would be zero or reduced), but the Buyer does not suffer a loss of physical energy delivery.
(d) The CfD settlement payment is calculated as the difference between a fixed Contract Price and a floating Hub Price, applied to actual metered generation. This is economically equivalent to a financial swap or hedge — it adjusts the effective price at which Seller monetizes the Project's output, but it does not transfer any property interest.
(e) Seller retains all risk and benefit of physical generation, including merchant price risk (hedged by the CfD), production risk, equipment risk, grid curtailment risk, and operational cost risk. Seller also retains all tax attributes associated with ownership, including depreciation, the ITC, and any production tax credit election that might otherwise be available.
In substance, the CfD is a financial instrument — a derivative contract — that provides price certainty to both Seller and Buyer without transferring any real or personal property interest. The CfD is economically identical to an interest rate swap or commodity swap, in which one party agrees to pay a fixed price and the other agrees to pay a floating price, with net settlement. The Commodity Futures Trading Commission ("CFTC") has recognized virtual PPAs as financial instruments subject to its jurisdiction, further supporting their characterization as derivatives rather than physical energy transactions.
For these reasons, the CfD structure does not raise the ownership concerns that could arise under a physical PPA or a sale-leaseback arrangement. Seller is and remains the sole owner of the facility, the sole entity entitled to depreciation deductions, and the sole entity entitled to claim the ITC.
B. No Partnership Risk
A potential concern in any arrangement between two parties involving a shared economic interest in a capital asset is whether the arrangement could be recharacterized as a partnership for federal income tax purposes. If the PPA were treated as creating a partnership between Saguaro Flats Solar LLC and Meridian, the partnership — not Saguaro Flats Solar LLC — would be the entity that owns the facility (or, alternatively, the partners would be treated as co-owners), and the allocation of the ITC would be governed by the partnership allocation rules under IRC § 704, which would require a separate and more complex analysis.
The IRS has addressed partnership characterization issues in the renewable energy context. Revenue Procedure 2007-65 provides a safe harbor for "flip partnerships" used in wind energy projects, under which a tax equity investor and a project sponsor form a partnership to own and operate a wind facility, with the ITC or production tax credits allocated primarily to the tax equity investor during an initial period and then "flipping" to the sponsor. The IRS issued Notice 2015-25 extending similar guidance to solar projects. These structures involve an intentional partnership formation with explicit profit-sharing and loss-sharing arrangements, capital contributions, and shared governance.
The CfD between Saguaro Flats Solar LLC and Meridian bears no resemblance to a partnership arrangement. Under the CfD:
(a) Meridian has no equity interest in Saguaro Flats Solar LLC or in any entity that owns the Project. Meridian is a contractual counterparty — a buyer under a financial derivative — not an equity investor or partner.
(b) There is no profit-sharing arrangement between the parties. Saguaro Flats Solar LLC is entitled to all profits (and bears all losses) from the operation of the facility. Meridian's only economic interest is in the CfD settlement payments, which are fixed contractual obligations independent of the facility's profitability.
(c) Meridian has no control over facility operations. Meridian does not participate in management decisions, does not approve capital expenditures, does not appoint officers or managers, and has no governance rights over Saguaro Flats Solar LLC.
(d) Meridian has no right to the ITC, to depreciation deductions, or to any other tax attribute associated with ownership of the facility. The PPA does not purport to allocate any tax benefits to Meridian.
(e) Meridian has not made and is not obligated to make any capital contribution to the Project. Meridian's sole obligation is to make (or receive) CfD settlement payments.
Under the multi-factor test for determining whether a partnership exists for federal income tax purposes — as articulated in Commissioner v. Culbertson, 337 U.S. 733 (1949), and its progeny — the parties must have joined together with the intent to carry on a business for profit, with each contributing something to the enterprise (such as money, property, or services) and sharing in the profits. None of these elements are present in the CfD arrangement. Meridian is not contributing capital, is not sharing in profits, and is not carrying on a business with Saguaro Flats Solar LLC. The CfD is an arm's-length commercial contract between unrelated parties, not a partnership or joint venture.
Recommendation: Notwithstanding the clear absence of partnership characteristics, we recommend that the PPA include express language confirming that the agreement does not create a partnership, joint venture, or association taxable as a corporation between the parties, and that each party is acting as an independent contractor in its own capacity. This language is standard in virtual PPA documentation and provides an additional layer of protection against any future recharacterization argument.
C. No Sale-Leaseback Recharacterization Risk
A sale-leaseback recharacterization could, in theory, shift tax ownership of the facility from Seller to Buyer if the IRS were to determine that the CfD structure, in substance, constitutes a sale of the facility to Meridian with a simultaneous leaseback to Saguaro Flats Solar LLC. This risk is relevant in certain physical PPA contexts where a buyer finances the construction of a dedicated facility and takes output under a long-term contract structured to resemble a financing lease. However, the CfD structure presents no sale-leaseback risk for the following reasons:
(a) The CfD does not convey any real or personal property interest to Buyer. There is no transfer of title, no conveyance of a leasehold interest, and no grant of any possessory right.
(b) Buyer has no right to possess, use, or control the facility. Buyer cannot enter the Project site, cannot direct operations, and cannot exclude others from the facility.
(c) Buyer does not bear the economic risks and benefits of ownership. Buyer does not benefit from appreciation in the facility's value, does not bear the risk of physical damage or obsolescence, and is not responsible for maintenance, repair, or replacement of equipment.
(d) The CfD creates only a financial obligation — a payment obligation that is contingent on the difference between two prices and a metered quantity. This is fundamentally different from a lease, which conveys a right to use and possess property for a specified period.
Under the factors set forth in IRS guidance and case law for distinguishing a lease from a service contract — including Revenue Ruling 55-540 and its progeny — the relevant considerations include (i) whether the purported lessee has control over the property, (ii) whether the purported lessee bears the risks and benefits of ownership, (iii) whether the purported lessee has an option to purchase the property, and (iv) whether the purported lessee has made an equity investment in the property. None of these factors point toward a lease characterization in the CfD context. The CfD is, in form and substance, a financial derivative contract, not a lease or a sale-leaseback.
Accordingly, there is no risk that the CfD would be recharacterized as a sale-leaseback arrangement, and no risk that tax ownership would be deemed transferred to Meridian under this theory.
D. No Service Contract Recharacterization
Another potential theory of recharacterization — also inapplicable here — is that the PPA constitutes a service contract under which Seller provides electricity-generation services to Buyer. If the CfD were characterized as a service contract, it could raise questions about whether Buyer is the beneficial owner of the facility under the service-contract analysis, similar to the analysis applied to certain outsourcing and managed-services arrangements.
The CfD is not a service contract because Seller is not providing electricity or any other service to Buyer. The Seller generates electricity and sells it into the ERCOT market on its own account. The Buyer is not a consumer of the electricity generated by the Project — Buyer sources its own electricity from the ERCOT market through its retail electric provider or through bilateral physical contracts. The CfD is a financial instrument that hedges Buyer's energy cost exposure to the ERCOT market, but Buyer's electricity consumption is entirely independent of the Project's generation.
This distinction is important for preserving Seller's status as the owner-operator of the facility. Under a service contract recharacterization, the IRS could argue that the Buyer is the true owner of the facility because the facility is operated for the Buyer's benefit, with the Seller acting merely as an operator or contractor. This argument fails entirely in the CfD context because (i) the facility is not operated for Buyer's benefit — it is operated for Seller's benefit, with Seller bearing all operational risk and retaining all operational control, (ii) Buyer does not consume the facility's output, (iii) Buyer does not direct or control the facility's operations, and (iv) the CfD settlement is a purely financial mechanism unrelated to the provision of any service.
E. Curtailment and Availability Provisions — Tax Ownership Implications
The PPA includes several commercial provisions that allocate economic risk between the parties, including availability guarantees and curtailment risk allocation. These provisions are currently under active negotiation between the parties and their respective counsel. We have been asked to analyze whether these provisions could have any impact on tax ownership or ITC eligibility.
Availability Guarantees. The PPA includes availability guarantee provisions under which Seller guarantees that the facility will achieve a minimum availability factor during each contract year. The parties are currently negotiating the threshold, with Meridian's initial proposal at 97.0% and Saguaro Flats Solar LLC's counterproposal at 95.0%. If the facility's actual availability falls below the guaranteed threshold, Seller is required to pay Buyer availability liquidated damages ("Availability LDs") calculated based on the shortfall between guaranteed and actual availability, multiplied by the expected generation and the Contract Price.
Availability LDs are a standard commercial feature of PPAs and do not transfer ownership or control of the facility to Buyer. Availability LDs are a form of contractual indemnification for underperformance — they compensate Buyer for the economic loss associated with lower-than-expected CfD settlement volumes. The payment of Availability LDs does not give Buyer any operational control, any right to cure the underperformance, or any interest in the facility or its assets. For tax purposes, Availability LDs are properly treated as a reduction in the effective price received by Seller under the CfD (or, alternatively, as a contractual damage payment), not as a transfer of ownership or an indication that Buyer bears the risks and benefits of ownership.
Curtailment Risk Allocation. The PPA also addresses the allocation of curtailment risk — the risk that ERCOT directs the facility to reduce output due to transmission congestion, system reliability concerns, or negative pricing. The current draft allocates curtailment risk to Seller for economic curtailment (where Seller elects to curtail because the ERCOT price is negative) and to Buyer for reliability curtailment directed by ERCOT. This allocation is a negotiated commercial term that affects the economic returns of the parties but does not transfer any ownership interest or control over the facility.
Neither the availability guarantee provisions nor the curtailment risk allocation provisions shift the benefits and burdens of ownership to Buyer. These provisions are financial risk allocation mechanisms within the CfD framework and are consistent with Seller's status as the sole owner and operator of the facility.
F. Change of Control Provisions — Tax Ownership Implications
The PPA includes change of control provisions that restrict the transfer of equity interests in Saguaro Flats Solar LLC (or in its direct or indirect parent entities) without Buyer's consent, subject to certain exceptions for (i) transfers to affiliates, (ii) transfers in connection with a tax equity financing, and (iii) transfers after the expiration of a specified lock-up period. These provisions are commercial in nature and are designed to protect Buyer's interest in the creditworthiness and operational capability of the Seller counterparty.
While the change of control provisions do not, in themselves, affect ITC eligibility, they intersect with an important tax consideration: the ITC recapture rules under IRC § 50(a).
Under IRC § 50(a)(1), if investment credit property (including energy property eligible for the ITC) is disposed of, or otherwise ceases to be investment credit property, before the close of the recapture period, the taxpayer must recapture a portion of the ITC previously claimed. The recapture amount decreases ratably over the five-year recapture period at a rate of 20% per year. That is:
• Disposition in Year 1: 100% recapture
• Disposition in Year 2: 80% recapture
• Disposition in Year 3: 60% recapture
• Disposition in Year 4: 40% recapture
• Disposition in Year 5: 20% recapture
• After Year 5: No recapture
For the Saguaro Flats Solar Project, the recapture period runs for five years from the placed-in-service date — approximately April 1, 2027 through March 31, 2032. During this period, any "disposition" of the facility — or any event that causes the facility to "cease to be investment credit property" — could trigger recapture of a portion of the $42,750,000 ITC.
The question of what constitutes a "disposition" for purposes of IRC § 50(a) is fact-specific. A sale of the physical assets of the facility clearly constitutes a disposition. A sale of 100% of the membership interests in Saguaro Flats Solar LLC (the disregarded entity that owns the facility) would also likely be treated as a disposition, because the sale of a disregarded entity's membership interests is treated as a sale of the underlying assets for federal income tax purposes under Treasury Regulation § 301.7701-3. However, a change of control at the CBR parent level — for example, a sale by Ridgepoint Capital Partners LP of its 68% equity interest in CBR — should not constitute a disposition of the energy property, because CBR (a corporation treated as a separate taxable entity) continues to own Saguaro Flats Solar LLC, which continues to own the facility. The "disposition" is of CBR equity, not of the energy property.
Nevertheless, the recapture risk associated with changes of control during the five-year window should be carefully managed. We recommend the following:
(a) The PPA and the organizational documents of Saguaro Flats Solar LLC should include language prohibiting any direct sale, assignment, or transfer of the energy property (i.e., the physical assets of the solar facility) or of the membership interests in Saguaro Flats Solar LLC during the five-year recapture period, except with the prior written consent of CBR's tax advisor and upon a determination that the proposed transfer would not trigger recapture.
(b) If the PPA's change of control provisions permit transfers during the recapture period, those provisions should include a condition that any permitted transferee must assume the obligation to maintain the facility as investment credit property and to refrain from any action that would trigger recapture.
(c) CBR should coordinate any Ridgepoint exit strategy (including a potential secondary sale of Ridgepoint's 68% interest in CBR) to ensure that the exit transaction is structured in a manner that does not trigger ITC recapture. A sale of Ridgepoint's interest in CBR should not trigger recapture, as discussed above, but the transaction should be reviewed by tax counsel before execution.
(d) The Credit Facility documents should include a corresponding ITC recapture protection covenant, and we understand from discussions with Helen Nakamura that the lender group's term sheet already contemplates such a covenant.
V. Prevailing Wage and Apprenticeship Requirements
To qualify for the 30% ITC rate — rather than the 6% base rate — the Saguaro Flats Solar Project must satisfy the prevailing wage and apprenticeship requirements enacted by the Inflation Reduction Act under IRC § 48(a)(10) and (11), as further implemented by Treasury and IRS guidance, including Notice 2022-61 (initial guidance on prevailing wage and apprenticeship requirements), proposed regulations under 29 CFR Part 5 (Department of Labor wage determinations), and subsequent notices and regulations.
Prevailing Wage Requirement. Under IRC § 48(a)(10)(A), the prevailing wage requirement is satisfied if, during the construction of the facility and during the five-year period beginning on the date the facility is placed in service (the "alteration or repair period"), any laborers and mechanics employed by the taxpayer or any contractor or subcontractor in the construction, alteration, or repair of the facility are paid wages at rates not less than the prevailing rates for construction, alteration, or repair of a similar character in the locality in which the facility is located, as determined by the Secretary of Labor in accordance with subchapter IV of chapter 31 of title 40, United States Code (the Davis-Bacon Act). The applicable prevailing wage rates for Pecos County, Texas are published by the Department of Labor and updated periodically.
For the construction period, this means that all laborers and mechanics employed by Sunbelt Power Construction LLC (as the EPC contractor) and all subcontractors performing work on the facility must be paid at or above the applicable Davis-Bacon prevailing wage rates for each craft classification. For the alteration or repair period (the five years following placed-in-service), this means that any alteration or repair work performed on the facility — including major maintenance, component replacements, and capital improvements — must also be performed at prevailing wage rates.
The IRA provides a correction mechanism under IRC § 48(a)(10)(B) that allows a taxpayer to cure prevailing wage violations by (i) making back payments to affected workers, plus interest, and (ii) paying a penalty to the IRS of $5,000 per worker per violation (or $10,000 for intentional disregard). While this correction mechanism provides a safety valve, it is preferable to ensure full compliance from the outset.
Apprenticeship Requirement. Under IRC § 48(a)(11), the apprenticeship requirement is satisfied if (i) the applicable percentage of total labor hours for the construction, alteration, or repair of the facility is performed by qualified apprentices, and (ii) the taxpayer and any contractor or subcontractor make a good faith effort to request qualified apprentices from registered apprenticeship programs. The applicable percentage is 12.5% for facilities that begin construction in 2024 and increases to 15% for facilities that begin construction in 2025 or later. Since the Saguaro Flats Solar Project is expected to begin construction in late 2025, the applicable apprenticeship percentage is 15%.
A "qualified apprentice" is an employee who is participating in a registered apprenticeship program that is registered under the Act of August 16, 1937 (commonly known as the National Apprenticeship Act), as amended. The apprenticeship requirement includes a good faith exception — if the taxpayer or contractor requests qualified apprentices from one or more registered programs and the request is denied or not responded to within five business days, the requirement is deemed satisfied for the labor hours that would otherwise need to be performed by apprentices.
EPC Contract Review. CBR must ensure that the EPC Contract with Sunbelt Power Construction LLC includes adequate prevailing wage compliance provisions and apprenticeship requirements, with appropriate flow-down obligations to all subcontractors. We have reviewed the executed EPC Contract and note the following:
(a) Section 14.3 of the EPC Contract includes a general provision requiring Sunbelt to comply with "all applicable federal, state, and local labor laws and regulations," but does not specifically reference the Davis-Bacon Act, the prevailing wage requirements of IRC § 48(a)(10), or the apprenticeship requirements of IRC § 48(a)(11).
(b) The EPC Contract does not include a specific prevailing wage compliance schedule or wage rate exhibit, nor does it include recordkeeping obligations specifically tied to the IRA prevailing wage and apprenticeship requirements.
(c) The EPC Contract does not include an indemnification provision specifically addressing the risk of ITC reduction resulting from Sunbelt's failure to comply with prevailing wage or apprenticeship requirements.
Recommendation: We recommend that the EPC Contract be amended to include (i) an express obligation for Sunbelt and all subcontractors to comply with the prevailing wage requirements of IRC § 48(a)(10) and the apprenticeship requirements of IRC § 48(a)(11), (ii) a prevailing wage schedule or exhibit incorporating the applicable Davis-Bacon rates for Pecos County, Texas, (iii) detailed recordkeeping obligations requiring Sunbelt to maintain certified payroll records and apprenticeship documentation for the duration of the statute of limitations applicable to CBR's ITC claim, and (iv) an indemnification provision under which Sunbelt agrees to indemnify CBR for any ITC reduction, recapture, or penalty resulting from Sunbelt's failure to comply with prevailing wage or apprenticeship requirements. We are prepared to draft these amendments for the EPC Contract and recommend that they be circulated to Sunbelt's counsel (Morgan & Lyle PLLC, attention Chris Devereaux) promptly.
VI. Drafting Recommendations for the PPA
Based on the analysis set forth in Sections III through V above, we recommend that the following provisions be incorporated into the Seller's Revised Draft PPA (Second Draft), targeted for circulation to Meridian's counsel (Hargreaves Winston LLP, attention Jennifer Aldric) on August 11, 2025. These provisions are designed to preserve Seller's tax ownership position, prevent recharacterization of the CfD, and protect the ITC.
A. Tax Ownership Preservation Language
The PPA should include an express provision, located in the representations and covenants article (or in a standalone tax article), confirming that Seller (Saguaro Flats Solar LLC) is and shall remain the sole owner of the facility for all purposes, including for federal, state, and local income tax purposes. The provision should state unambiguously that nothing in the PPA is intended to, or shall be construed to, (i) transfer any ownership interest in the facility, or any portion thereof, to Buyer, (ii) create any lien, security interest, or encumbrance on the facility in favor of Buyer (other than any contractual rights under the PPA itself), or (iii) transfer, assign, or convey any tax benefits, tax attributes, or tax credits associated with the facility — including, without limitation, the investment tax credit under IRC § 48, depreciation deductions under IRC § 167 or § 168, or any other tax attribute — to Buyer.
This provision serves both a substantive and a prophylactic purpose. Substantively, it confirms the parties' shared intent that the CfD is a financial arrangement and that Seller retains all indicia of ownership. Prophylactically, it provides the IRS and any reviewing court with clear evidence of the parties' intent, which is a relevant (though not dispositive) factor in characterization disputes.
B. No-Partnership / No-Joint-Venture Clause
The PPA should include a provision stating that the PPA does not create and shall not be deemed to create a partnership, joint venture, agency relationship, fiduciary relationship, or association taxable as a corporation between the parties for any purpose, including for federal, state, or local income tax purposes. The provision should further confirm that each party is acting solely as an independent contractor in its own capacity and for its own account, and that neither party has the authority to bind the other or to act as the other's agent.
This provision is standard in virtual PPA documentation and is consistent with similar language found in ISDA Master Agreements and Edison Electric Institute form agreements. While the absence of a no-partnership clause would not, in itself, create a partnership (the existence of a partnership is determined under federal law based on the objective characteristics of the arrangement, not the parties' labeling), the inclusion of this clause is prudent and supports the parties' position in any future inquiry.
C. ITC Recapture Protection
The PPA should include a covenant, binding on Seller, that Seller shall not take any action — or fail to take any action — that would cause the facility to cease to be "investment credit property" within the meaning of IRC § 50(a) during the recapture period (the five-year period beginning on the placed-in-service date). Specifically, Seller should covenant that it will not, during the recapture period, (i) sell, transfer, or otherwise dispose of the facility or any material portion thereof (other than replacement of worn or damaged components in the ordinary course of maintenance), (ii) convert the facility to a use that does not qualify as energy property under IRC § 48, or (iii) take any other action that would trigger ITC recapture.
If the change of control article of the PPA permits transfers of equity interests in Saguaro Flats Solar LLC during the recapture period, the PPA should include a condition precedent to any such transfer requiring that any permitted transferee execute a written assumption agreement, in form and substance reasonably satisfactory to Buyer, pursuant to which the transferee assumes the obligation to maintain the facility as investment credit property and to refrain from any action that would trigger ITC recapture. This protects Buyer's interest in the continued operation of the facility as a CfD settlement reference asset.
Additionally, the PPA should include a representation by Seller that it intends to claim the ITC with respect to the facility and will not voluntarily elect out of the ITC under IRC § 48 or elect the production tax credit under IRC § 45 in lieu of the ITC, without Buyer's prior written consent (which may be withheld in Buyer's sole discretion). While this representation primarily protects Seller's own economic interest, it also provides Buyer with assurance that the Project's financial model — which underpins the Contract Price — is based on the ITC assumption.
D. Characterization of CfD Payments
The PPA should define the CfD settlement payments with precision and in a manner that supports the financial derivative characterization. Specifically, the PPA should state that all settlement payments made under the PPA are payments under a "contract for differences" or "financial settlement contract," and are not payments for the purchase or sale of electricity, capacity, ancillary services, or renewable energy certificates. The PPA should further state that the parties intend the CfD to be treated as a financial hedge or swap for all purposes, including for federal income tax, regulatory, and accounting purposes.
This characterization language is important for several reasons beyond the ITC analysis, including (i) regulatory compliance (a financial CfD is generally not subject to state public utility regulation, whereas a physical power sale may be), (ii) accounting treatment (a CfD may qualify for derivative accounting under ASC 815, whereas a physical PPA may require different treatment), and (iii) bankruptcy treatment (a financial CfD may qualify as a "swap agreement" under the Bankruptcy Code, providing certain safe harbor protections for non-defaulting counterparties). For ITC purposes, the characterization language reinforces the conclusion that the CfD does not transfer any property interest or create any arrangement inconsistent with Seller's tax ownership.
E. Indemnification for Tax Consequences
We recommend that the PPA include a mutual indemnification provision addressing the risk of adverse tax consequences arising from a recharacterization of the PPA by a taxing authority. Specifically:
(a) If the IRS or any other taxing authority recharacterizes the CfD as creating a partnership, joint venture, sale-leaseback, service contract, or other arrangement that adversely affects Seller's ability to claim the ITC or any other tax benefit associated with ownership of the facility, and such recharacterization is attributable to the actions or omissions of Buyer (including Buyer's filing positions or public statements inconsistent with the CfD characterization), Buyer should indemnify Seller for all resulting losses, including the value of any lost or recaptured ITC, additional taxes, interest, and penalties.
(b) Conversely, if Seller's actions or omissions cause a recharacterization that adversely affects Buyer's tax position (for example, if the IRS were to treat the CfD settlement payments as something other than ordinary income or loss to Buyer), Seller should indemnify Buyer for all

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