PRIVILEGED & CONFIDENTIAL — ATTORNEY WORK PRODUCT
This memorandum is protected by the attorney-client privilege and the work product doctrine. It has been prepared by Calderwood & Harkness LLP at the direction of Calloway-Briggs Renewables Inc. and its affiliates in connection with legal advice related to the negotiation of the Saguaro Flats Solar PPA. Distribution is limited to the individuals identified below. Do not forward, copy, or distribute without prior authorization from Patricia Dunmore.
Internal Redline Comparison & Markup Notes
Buyer's Redline vs. Seller's Form Power Purchase Agreement
Matter: Calloway-Briggs Renewables Inc. — Solar PPA with Meridian DataCore Solutions Inc.
Matter No.: 1015-00002
Date: August 2, 2025
Prepared by: Brett Callahan, Lead Associate, Energy & Infrastructure David Stanton, Working Associate, Energy & Infrastructure
Reviewed by: Patricia Dunmore, Responsible Partner, Energy & Infrastructure
Distribution: Internal Calderwood & Harkness LLP use only; to be shared with client (Rachel Muñoz, General Counsel, Calloway-Briggs Renewables Inc.; Janet Okafor, SVP Origination, Calloway-Briggs Renewables Inc.) for discussion purposes only.
Reference Documents:
(i) Seller's Form PPA (First Draft), dated July 14, 2025, circulated to Hargrove & Linden LLP on behalf of Saguaro Flats Solar LLC (the "Seller's Form");
(ii) Buyer's Redline of the Seller's Form PPA, received August 1, 2025 from Hargrove & Linden LLP (Evelyn Crumveth, Partner / Ryan Matsuda, Associate) on behalf of Meridian DataCore Solutions Inc. (the "Buyer's Redline").
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1. Executive Summary
1.1 Purpose
This memorandum catalogs and analyzes all substantive changes reflected in the Buyer's Redline of the Seller's Form PPA for the Saguaro Flats Solar Project, a 150 MWac (195 MWdc) ground-mounted, single-axis tracking solar photovoltaic facility located in Pecos County, Texas (the "Facility" or the "Project"). The Buyer's Redline was received on August 1, 2025 from Hargrove & Linden LLP (Austin, TX), lead partner Evelyn Crumveth and associate Ryan Matsuda, acting on behalf of Meridian DataCore Solutions Inc. ("Buyer" or "Meridian"). This memorandum is intended to inform the client discussion regarding counter-redline strategy and to identify those provisions requiring priority attention from a commercial, legal, and project-finance bankability perspective.
1.2 Overall Assessment
The Buyer's Redline contains approximately sixty-seven (67) substantive changes spread across fifteen (15) of the PPA's seventeen articles and six exhibits. Of these, twenty-two (22) are classified as non-substantive or conforming (Category A), twenty-six (26) as moderate (Category B), and nineteen (19) as material or high priority (Category C). The most significant departures from the Seller's Form relate to the following five areas:
(a) Availability guarantee thresholds and liquidated damages — Buyer seeks to increase the guaranteed availability threshold from 95.0% to 97.0%, double the LD rate and cap, lower the termination trigger floor, and eliminate the consecutive-period requirement for termination;
(b) Change of control provisions — Buyer seeks to replace Seller's notice-plus-credit-test regime with a prior-consent model, introduce a $1,500,000 consent fee, and delete reciprocal protections applicable to Buyer's own change of control;
(c) Removal of the Buyer corporate guaranty — Buyer has deleted Exhibit C in its entirety and all references to the Buyer's $14,000,000 corporate guaranty obligation;
(d) Curtailment risk allocation — Buyer seeks to cap Seller's right to curtail for negative pricing at 500 hours per year and to shift 200 hours per year of grid-ordered curtailment risk to Seller; and
(e) Force majeure definitions — Buyer has narrowed the force majeure definition by removing supply chain disruptions and grid curtailment and has introduced a 180-day FM cap with a no-payment termination right.
Each of these areas is discussed in detail in Sections 5.1 through 5.5 below. In addition to these "big five" issues, there are a number of moderate-priority changes (Section 4) and exhibit-level changes (Section 6) that will require attention in the counter-redline.
1.3 Transaction Overview
The following summary of the transaction is provided for context:
PPA Structure: Virtual (financial) PPA / contract for differences ("CfD") settling at the ERCOT West Hub. Under the CfD settlement mechanics, for each MWh generated and settled at the Hub, if the Hub Price exceeds the Contract Price, Seller pays the difference to Buyer; if the Hub Price is below the Contract Price, Buyer pays the difference to Seller.
Term: Twenty (20) years from the Commercial Operation Date. Expected COD is April 1, 2027; expected end-of-term is March 31, 2047.
Aggregate Nominal Contract Value: Approximately $140,000,000 over the 20-year term (based on P50 generation of 350,000 MWh/year, Contract Price of $20.00/MWh in Year 1, escalating at 1.50% per annum compounding from Year 6).
Parties:
• Seller: Saguaro Flats Solar LLC, a Delaware limited liability company and wholly-owned subsidiary of Calloway-Briggs Renewables Inc. ("CBR").
• Buyer: Meridian DataCore Solutions Inc., a Delaware corporation (Nasdaq: MDCS), a hyperscale data center owner and operator headquartered in Austin, Texas.
Key Third Parties:
• Seller's Counsel: Calderwood & Harkness LLP (Patricia Dunmore, Partner; Brett Callahan, Lead Associate; David Stanton, Working Associate).
• Buyer's Counsel: Hargrove & Linden LLP, Austin, TX (Evelyn Crumveth, Partner; Ryan Matsuda, Associate).
• Seller's Equity Sponsor: Ridgepoint Capital Partners LP (68% equity stake in CBR; managing partner: Alan Driscoll).
• EPC Contractor: Sunbelt Power Construction LLC (fixed-price turnkey EPC contract for construction of the Facility).
• Independent Engineer: Gresham Engineering Advisors Inc.
• Project-Finance Lenders: Tralvendo National Bank (administrative agent and lead arranger), Osprey Commercial Lending Corp., Grandview Savings Bank, and Blue Prairie Capital Markets LLC (collectively, the "Lender Group"), under a $108,000,000 construction-to-term loan facility.
• Lender's Counsel: Whitfield Stroval & Cade LLP (Philip Thornton, Partner).
• Lender-Side Advisor (Calderwood & Harkness): Helen Nakamura, Counsel, Project Finance.
• CBR Finance Team: Derek Engstrom, VP Project Finance.
• Energy Consultant: Heliograph Energy Consulting LLC (P50 / P90 energy yield assessments).
• Insurance Broker: Fieldstone Risk Advisors LLC.
• Insurance Carriers: Commonwealth Mutual; Ridgeway Casualty Group.
• Transmission Service Provider: West Texas Wires LLC (interconnection at Ft. Stockton 345 kV Substation).
• ERCOT Queue Position: ERCOT-GI-2024-0437 (LGIA executed May 15, 2025).
1.4 Recommended Next Steps
Based on the analysis set forth below, we recommend the following immediate next steps:
(a) Prepare separate client memoranda on the key contested issues — specifically, (i) availability guarantee proposals and (ii) change of control proposals — for circulation to Rachel Muñoz, Janet Okafor, and Derek Engstrom;
(b) Schedule an internal strategy call with Rachel Muñoz, Janet Okafor, and Derek Engstrom for the week of August 4, 2025 to discuss counter-redline strategy and prioritize concessions;
(c) Develop detailed counter-redline positions for each Category C issue, informed by the financial modeling and lender coordination described below;
(d) Coordinate with Helen Nakamura on lender bankability implications, particularly with respect to the availability provisions, change of control, termination payment cap, and Lender Consent Agreement modifications; and
(e) Prepare and circulate the Seller's Revised Draft PPA (Second Draft / Counter-Redline) for delivery to Hargrove & Linden LLP by August 11, 2025.
The detailed action items and responsible parties are set forth in Section 8 below.
2. Methodology
2.1 Comparison Approach
This memorandum reflects a section-by-section, clause-by-clause comparison of the Seller's Form PPA (dated July 14, 2025) against the Buyer's Redline (received August 1, 2025). The comparison was conducted manually by David Stanton and reviewed by Brett Callahan, with reference to Hargrove & Linden's own redline markings (tracked changes in Microsoft Word format). Where Buyer's counsel inserted explanatory comments or marginal notes in the Word document, those comments are referenced and summarized in the relevant sections below. All references to specific PPA articles and sections correspond to the numbering in the Seller's Form unless otherwise noted; Buyer's Redline did not alter the article numbering.
2.2 Classification System
Each change identified in the Buyer's Redline has been classified according to the following three-category system:
Category A — Accepted / Non-Substantive: Conforming, typographical, or stylistic edits with no legal or commercial impact. These changes include formatting corrections, defined-term cross-reference fixes, capitalization adjustments, notice address updates, and similar ministerial edits. Category A changes are summarized briefly in Section 3 and are recommended for acceptance without further negotiation.
Category B — Moderate: Changes that are worth noting and that may require discussion or minor adjustment, but that are likely resolvable without significant negotiation or client escalation. These include commercially reasonable modifications, standard-market provisions not included in the Seller's Form, and adjustments that are generally acceptable subject to protective language or modest negotiation. Category B changes are discussed in Section 4.
Category C — Material / High Priority: Substantive changes that represent significant departures from the Seller's Form and that require client input, strategic assessment, and potentially extended negotiation with Buyer's counsel. These include provisions with direct financial impact on the Seller, provisions affecting project-finance bankability, provisions that alter fundamental risk allocation between the parties, and provisions that are inconsistent with market standards for utility-scale solar PPAs. Category C changes are discussed in Section 5.
2.3 Priority Flags
Within Category C, each issue has been assigned a priority flag as follows:
• HIGH: Requires immediate client attention and is expected to be a principal point of negotiation. Likely to require separate client memorandum and/or coordination with project-finance lenders.
• MODERATE-HIGH: Significant issue that will require negotiation but may be more readily resolved than HIGH-priority issues through compromise positions.
• LOW-MODERATE: Important but unlikely to be a deal-breaker; can likely be resolved through reasonable negotiation.
2.4 Annotations
Throughout this memorandum, annotations reference specific PPA article and section numbers as they appear in the Seller's Form. Where the Buyer's Redline adds new sections or renumbers existing provisions, we identify the relevant Buyer's Redline section number parenthetically. Cross-references to other sections of this memorandum are provided where related issues are discussed in multiple locations.
3. Category A — Non-Substantive / Conforming Changes
This section summarizes changes in the Buyer's Redline that are classified as non-substantive, conforming, or ministerial in nature. We recommend accepting all Category A changes without further negotiation or client escalation.
3.1 Defined Terms and Formatting
Throughout the Buyer's Redline, Buyer's counsel made various defined-term cross-reference corrections and formatting clean-up edits. These include the following:
(a) Correction of internal cross-references in Articles 1, 3, 6, and 15 where defined terms were referenced without proper capitalization or where section numbers were incorrect in the Seller's Form (likely drafting errors carried over from a prior template);
(b) Modification of certain defined-term capitalization conventions throughout the agreement to align with Buyer's house style. For example, Buyer's counsel capitalized "Contract Year" and "Delivery Period" uniformly, whereas the Seller's Form inconsistently capitalized these terms in certain provisions;
(c) Insertion of subsection headings within Articles 6, 10, and 13, where the Seller's Form used run-on paragraphs for lengthy provisions. The added headings improve readability without altering substantive content;
(d) Minor grammatical corrections, including comma placement, serial comma usage, and replacement of "which" with "that" in restrictive clauses; and
(e) Standardization of numerical formatting (e.g., "$20.00 per MWh" rendered consistently throughout rather than alternating between "$20.00/MWh" and "$20 per MWh").
Assessment: Accept all. These edits improve consistency and readability and have no substantive legal or commercial impact. No client input required.
3.2 Notice Provisions (Article 17.2)
Buyer's Redline updated the notice information for Meridian DataCore Solutions Inc. to reflect current contact information. The updated notice address is as follows:
Meridian DataCore Solutions Inc. 700 Lakeshore Parkway, Building C Austin, TX 78746
Attention: VP, Procurement & Contracts (Amara Osei)
With a copy to: Deputy General Counsel (Victor Langford)
The Seller's notice address remains as stated in the Seller's Form:
Saguaro Flats Solar LLC c/o Calloway-Briggs Renewables Inc. 4200 Travis Street, Suite 1800 Houston, TX 77002
Attention: General Counsel (Rachel Muñoz)
Buyer also added Hargrove & Linden LLP as a courtesy copy addressee for notices to Buyer, which is a common and expected inclusion in transactional documents where counsel of record is identified.
Assessment: Accept. Conforms to standard practice. The Seller should confirm that the Seller's notice address and attention line remain current and that no additional copy parties (e.g., Janet Okafor or Derek Engstrom) should be added. Coordination with Rachel Muñoz recommended.
3.3 Recitals
Buyer's counsel added two sentences to the Recitals section of the PPA. The first describes Meridian's status as a "hyperscale data center owner and operator with facilities across the United States." The second provides a minor clarification to the description of Buyer's purpose in entering the PPA, stating that the PPA supports "Buyer's corporate sustainability, renewable energy procurement, and carbon reduction goals, including commitments to achieve 100% renewable energy matching by 2030." These additions are descriptive and precatory in nature and do not create binding obligations.
Assessment: Acceptable, provided the statements are accurately stated and do not create any unintended representations or warranties. We recommend a brief review to confirm that the sustainability language does not inadvertently impose compliance obligations on Seller. Minor language review needed, but we do not anticipate any issues. Category A classification is appropriate.
4. Category B — Moderate Changes
This section discusses changes in the Buyer's Redline that are classified as moderate — worth noting and potentially requiring minor negotiation or protective language, but generally resolvable without significant escalation.
4.1 Definitions — "Commercial Operation Date" (Article 1)
Seller's Form: The Seller's Form defined "Commercial Operation Date" or "COD" as the date on which Seller delivers to Buyer a certificate executed by an authorized officer of Seller (the "COD Certificate") confirming that (a) the Facility has been substantially completed in accordance with the EPC contract, (b) the Facility has achieved Initial Synchronization with the ERCOT grid, (c) the Facility has received all material permits and approvals necessary for commercial operation, and (d) Seller has executed and delivered the interconnection agreement with the applicable transmission service provider (West Texas Wires LLC) and the Facility is interconnected with and capable of delivering energy to the ERCOT grid at the Ft. Stockton 345 kV Substation.
Buyer's Redline: Buyer's counsel added a fifth requirement: that Seller deliver, concurrently with the COD Certificate, an independent engineer's certificate from Gresham Engineering Advisors Inc. (the "IE Certificate") confirming that the Facility has achieved not less than 95% of nameplate AC capacity (i.e., not less than 142.5 MWac of 150 MWac nameplate) during COD performance testing conducted in accordance with Exhibit A. The Buyer's Redline also specifies that the COD testing protocol shall include a minimum continuous run period of 72 hours and shall measure energy production against expected irradiance conditions.
Analysis: Independent engineer certification of COD is a common feature of bankable utility-scale solar PPAs and is typically required by project-finance lenders as well. The concept itself is not objectionable and may in fact be required by Tralvendo's credit agreement as a condition precedent to the term conversion of the construction loan. However, the 95%-of-nameplate threshold warrants careful review. The Facility has a DC:AC ratio of 1.30 (195 MWdc / 150 MWac), which means inverter clipping will occur during peak irradiance periods. While the Facility is designed to deliver 150 MWac under standard test conditions, achieving 142.5 MWac (95% of nameplate) on a sustained basis during a 72-hour test window depends on irradiance conditions, ambient temperature, and module soiling. A lower threshold of 90% of nameplate (135 MWac) may be more appropriate, particularly given seasonal variations in solar irradiance in Pecos County during the expected COD window (April 2027).
Assessment: MODERATE. The independent engineer COD certification concept is acceptable and should be discussed with Helen Nakamura to confirm alignment with lender requirements. The 95%-of-nameplate threshold should be flagged for discussion with the client and with Gresham Engineering Advisors Inc. (independent engineer). We recommend proposing 90% of nameplate as Seller's counter-position, with willingness to settle at 92%–93% if needed.
4.2 Definitions — "Expected COD" and "Guaranteed COD" (Article 1)
Seller's Form: The Seller's Form defined "Expected COD" as April 1, 2027 and provided that if COD had not been achieved within eighteen (18) months after the Expected COD (i.e., by October 1, 2028), Buyer would have the right to terminate the PPA upon thirty (30) days' written notice. The Seller's Form contained no concept of "Guaranteed COD" and imposed no delay liquidated damages on the Seller for failure to achieve COD by any particular date.
Buyer's Redline: Buyer's counsel inserted a new defined term, "Guaranteed COD," set at October 1, 2027 — six months after the Expected COD of April 1, 2027. The Buyer's Redline further provides that if COD has not been achieved by the Guaranteed COD, Seller shall pay Buyer delay liquidated damages in the amount of $3,500 per day (approximately $1,277,500 per year, or approximately $106,458 per month) for each day from the Guaranteed COD until the earlier of (x) the date on which COD is achieved and (y) the date on which the PPA is terminated. The Buyer's Redline retains the Seller's 18-month termination backstop but recalibrates it to run from the Expected COD (so the termination date remains October 1, 2028).
Analysis: Delay liquidated damages are common in physical PPAs and in some virtual PPAs with creditworthy counterparties. The concept is not inherently unreasonable, but several elements require analysis:
(a) Quantum: At $3,500 per day, the delay LD exposure from October 1, 2027 through October 1, 2028 (365 days) would total approximately $1,277,500. This is a meaningful amount but is modest relative to the total project cost ($108,000,000 credit facility) and the aggregate nominal PPA value ($140,000,000). The quantum should be reviewed by Derek Engstrom to assess its reasonableness as a pre-estimate of Buyer's actual damages from delayed commencement of the CfD settlement stream.
(b) Interaction with Force Majeure: The Buyer's Redline does not clearly address whether the Guaranteed COD is extended by Force Majeure events. The Seller's Form extended the termination backstop date by the duration of any FM event; the Buyer's Redline should similarly extend the Guaranteed COD. If FM does not extend the Guaranteed COD, Seller could be exposed to delay LDs for events entirely beyond its control.
(c) Coordination with Tralvendo: The construction loan under the Tralvendo credit facility has a scheduled conversion date tied to the Expected COD. An additional LD obligation running from month seven after Expected COD needs to be factored into the financial model and discussed with Derek Engstrom and Helen Nakamura.
Assessment: MODERATE. The concept of delay LDs tied to a Guaranteed COD is negotiable. We recommend accepting the concept in principle but proposing (i) a Guaranteed COD of January 1, 2028 (nine months after Expected COD, rather than six), (ii) delay LDs of $2,500 per day (rather than $3,500), and (iii) clear extension of the Guaranteed COD by the duration of any FM event. Additionally, any delay LDs should be subject to a cap (e.g., $1,500,000 aggregate) to limit total exposure.
4.3 Delivery Point / Settlement Hub (Article 4)
Seller's Form: The Seller's Form specified the ERCOT West Hub as the settlement point for the CfD, under which the floating price component of the settlement formula is the real-time settlement point price at the ERCOT West Hub for each settlement interval. The Seller's Form did not address congestion or transmission loss costs between the Facility's physical point of interconnection (the Ft. Stockton 345 kV Substation) and the ERCOT West Hub — i.e., the Seller's Form was silent on basis risk allocation.
Buyer's Redline: Buyer accepted the ERCOT West Hub as the settlement hub but added the following language to Section 4.3:
"Seller shall bear all costs and risks associated with congestion charges, transmission losses, and any other charges or adjustments incurred or imposed between the Facility's Point of Interconnection and the Settlement Hub, and the Contract Price shall not be adjusted to account for any such charges. For purposes of the CfD settlement under Section 4.2, the Delivered Quantity shall be reduced by the volume of energy losses between the Point of Interconnection and the Settlement Hub."
Analysis: This is a significant commercial issue. In a virtual PPA / CfD structure, the settlement mechanics are purely financial — no physical delivery of energy occurs from Seller to Buyer. The CfD settles on the difference between the Contract Price and the Hub Price at the ERCOT West Hub for each MWh of metered generation. The Buyer's proposed language would effectively shift basis risk — the risk that the locational marginal price at the Facility's interconnection point differs from the price at the ERCOT West Hub — entirely to the Seller. In addition, Buyer's proposal to reduce the "Delivered Quantity" by transmission losses would reduce the number of MWh settling under the CfD, directly reducing Seller's revenue.
Basis risk in ERCOT's West zone is a known and growing concern. The Facility is located in Pecos County, an area of significant renewable energy development with documented transmission congestion. The price spread between the Facility's interconnection node and the ERCOT West Hub can be substantial during periods of high solar production. Seller has no ability to control or mitigate this basis risk, which is a function of ERCOT grid topology and dispatch.
In a financial PPA, the standard approach is for the CfD to settle at the Hub, with basis risk implicitly shared or allocated by reference to the Hub price without additional adjustment. Buyer's proposal would add a second layer of locational risk on top of the Hub settlement, which is inconsistent with the virtual PPA structure.
Assessment: MODERATE. We recommend resisting Buyer's proposed basis risk allocation in its entirety. The CfD should settle at the ERCOT West Hub based on metered generation at the interconnection point, without reduction for congestion or transmission losses. This is a financial PPA, not a physical delivery contract, and Seller should not bear locational risk between the interconnection point and the Hub. This issue should be flagged for Janet Okafor's attention as it has direct commercial implications for the Project's revenue profile.
4.4 Scheduled Maintenance (Article 6.4)
Seller's Form: The Seller's Form provided that scheduled maintenance hours — up to a maximum of 200 hours per Contract Year — would be excluded from the availability calculation, provided that Seller gives Buyer at least thirty (30) days' advance written notice of scheduled maintenance windows and uses commercially reasonable efforts to schedule maintenance during low-irradiance periods (November through February).
Buyer's Redline: Buyer reduced the scheduled maintenance allowance from 200 hours per year to 150 hours per year. Buyer also added a requirement that Seller provide at least sixty (60) days' advance notice of scheduled maintenance (rather than thirty).
Analysis: A 200-hour annual maintenance allowance is standard for utility-scale solar facilities and reflects the practical requirements for module cleaning, inverter maintenance, tracker servicing, substation maintenance, and other routine O&M activities. Reducing the allowance to 150 hours narrows the maintenance window by 25% and could force Seller to defer necessary maintenance or risk triggering availability shortfalls. This issue is compounded by Buyer's simultaneous proposal to increase the availability guarantee from 95.0% to 97.0% (see Section 5.1.1 below) — the combination of a higher availability threshold and a narrower maintenance exclusion window creates a "squeeze" that materially increases the risk of availability LDs.
The increased notice period (60 days rather than 30 days) is less problematic but may be impractical for unplanned-but-schedulable maintenance (e.g., inverter replacement following an unexpected failure that does not constitute an emergency outage).
Assessment: MODERATE. We recommend retaining the 200-hour annual maintenance allowance. If a compromise is needed, we could accept a reduction to 175 hours, but 150 hours is below market norms for a facility of this size and technology. On the notice period, we recommend retaining 30 days but adding a provision permitting shorter notice for urgent-but-non-emergency maintenance with Buyer's consent (not to be unreasonably withheld).
4.5 Metering (Article 5)
Seller's Form: The Seller's Form provided that Seller shall own, install, operate, and maintain the revenue-quality meter at the Facility's point of interconnection with the ERCOT grid (the "Revenue Meter"), and that the Revenue Meter shall be the sole basis for determining the Delivered Quantity for purposes of CfD settlement. Meter calibration and testing would be conducted annually by a qualified third-party metering services provider, with results shared with Buyer.
Buyer's Redline: Buyer added the following rights:
(a) The right to install, at Buyer's sole cost and expense, a check meter at the Facility's point of interconnection (the "Check Meter"), for the purpose of verifying the accuracy of the Revenue Meter;
(b) The right to audit Seller's SCADA data on a quarterly basis, with reasonable advance notice (not less than ten (10) Business Days);
(c) A dispute resolution mechanism providing that if the Check Meter and Revenue Meter readings diverge by more than 0.5% in any calendar month, the parties shall promptly conduct a joint investigation and recalibration; and
(d) A provision that if a metering error is discovered, the CfD settlement shall be retroactively adjusted for the period of the error, up to a maximum look-back period of twelve (12) months.
Analysis: Check metering rights are standard in utility-scale PPAs, and we have seen substantially similar provisions in comparable transactions. The key protective principles from Seller's perspective are (i) Buyer bears all costs of the Check Meter installation, operation, and maintenance; (ii) Seller retains exclusive ownership, operation, and control of the Revenue Meter; and (iii) the Revenue Meter remains the official meter for settlement purposes unless a metering error is confirmed through the dispute resolution process. Buyer's proposed 0.5% divergence threshold for triggering investigation is reasonable. The twelve-month look-back for retroactive settlement adjustments is at the long end of market norms (six to twelve months is typical) but is acceptable.
Assessment: MODERATE. Generally acceptable. We recommend accepting the check metering and SCADA audit provisions with the following protective language: (i) express confirmation that Seller retains exclusive ownership and operational control of the Revenue Meter; (ii) a requirement that any Buyer audit of SCADA data be conducted through a mutually agreed independent third party (to protect proprietary operational data); and (iii) confirmation that the Check Meter shall not be used as the basis for CfD settlement unless the Revenue Meter is demonstrated to be inaccurate by more than the 0.5% threshold.
4.6 Assignment — General (Article 9)
Seller's Form: The Seller's Form provided that neither party may assign its rights or obligations under the PPA without the prior written consent of the other party, which consent shall not be unreasonably withheld, conditioned, or delayed; provided, however, that (a) Seller may assign the PPA to any direct or indirect affiliate of Seller or of Calloway-Briggs Renewables Inc. without Buyer's consent, subject to notice, and (b) Seller may make a collateral assignment of its rights under the PPA to its project-finance lenders without Buyer's consent, subject to the terms of the Lender Consent Agreement (Exhibit F).
Buyer's Redline: Buyer restricted Seller's assignment rights more tightly by deleting the affiliate assignment carve-out. Under the Buyer's Redline, Seller may not assign the PPA without Buyer's prior written consent (not to be unreasonably withheld, conditioned, or delayed), except for a collateral assignment to project-finance lenders (which remains permitted without consent, subject to the Lender Consent Agreement). The Buyer's Redline also added a reciprocal restriction on Buyer's own assignment rights, requiring Seller's prior written consent (not to be unreasonably withheld).
Analysis: The deletion of the affiliate assignment carve-out is noteworthy. CBR's corporate structure involves multiple project-level SPVs, and Ridgepoint Capital Partners LP's eventual exit strategy may involve restructuring the ownership of these SPVs or selling them to a successor platform company. The affiliate assignment carve-out is important for maintaining flexibility in CBR's corporate organization and for facilitating Ridgepoint's exit without requiring Buyer consent at every stage. The lender collateral assignment carve-out is preserved, which is essential for the Tralvendo credit facility, and the addition of a reciprocal restriction on Buyer's assignment is favorable to Seller.
Assessment: MODERATE. We recommend retaining the affiliate assignment carve-out, which is standard in project-finance PPAs. If Buyer insists on some limitation, we could propose a narrowed carve-out that limits affiliate assignments to entities that are directly or indirectly controlled by CBR or by any entity that controls CBR (which would capture Ridgepoint-controlled affiliates). The lender collateral assignment carve-out must be preserved without modification. The reciprocal restriction on Buyer's assignment is acceptable and should be retained.
4.7 Representations and Warranties (Article 12)
Seller's Form: The Seller's Form contained standard mutual representations (due organization, authority, no conflict, enforceability) and certain Seller-specific representations, including (a) a representation that Seller holds all material permits and approvals for the construction and operation of the Facility, (b) a representation that the Facility is and will be in compliance with all applicable laws and environmental regulations, and (c) a representation regarding the "adequacy of the solar resource at the Site for the generation of solar energy in the quantities contemplated by this Agreement."
Buyer's Redline: Buyer made two changes:
(a) Buyer added a mutual representation regarding no pending or threatened litigation: "There is no action, suit, proceeding, or investigation pending or, to such Party's knowledge, threatened against such Party before any court or governmental authority that would reasonably be expected to materially and adversely affect such Party's ability to perform its obligations under this Agreement."
(b) Buyer deleted the Seller's representation regarding adequacy of the solar resource at the site.
Analysis: The mutual litigation representation is standard and widely used in comparable PPAs and commercial agreements. It is acceptable and creates no additional risk for Seller beyond a confirmation of the absence of material pending litigation — a representation that Seller should be able to make accurately. The deletion of the solar resource representation is, from Seller's perspective, favorable. Seller should not warrant solar irradiance levels, which are inherently variable, subject to weather patterns, and outside Seller's control. The appropriate mechanism for addressing solar resource risk is the availability guarantee (which measures equipment availability, not solar irradiance) and the P50/P90 energy yield analysis prepared by Heliograph Energy Consulting LLC, which is provided for informational purposes only and does not form part of the contractual obligations.
Assessment: MODERATE. The mutual litigation representation is acceptable. The deletion of the solar resource representation is favorable to Seller and should be accepted. No client input required on these changes.
4.8 Insurance Requirements (Exhibit E)
Seller's Form: Exhibit E of the Seller's Form required Seller to maintain the following minimum insurance coverages throughout the PPA term: (a) commercial general liability ("CGL") insurance of not less than $5,000,000 per occurrence and $10,000,000 in the aggregate; (b) workers' compensation insurance as required by applicable law; (c) employer's liability insurance of not less than $1,000,000 per occurrence; (d) automobile liability insurance of not less than $1,000,000 combined single limit; (e) all-risk property insurance covering the Facility in an amount equal to the full replacement value of the Facility; and (f) pollution legal liability insurance of not less than $5,000,000 per occurrence.
Buyer's Redline: Buyer made two changes to the insurance requirements:
(a) Increased the minimum CGL coverage from $5,000,000 to $10,000,000 per occurrence (with a corresponding increase in the aggregate to $20,000,000); and
(b) Added a new requirement for cyber liability insurance in an amount of not less than $5,000,000 per occurrence, covering claims arising from unauthorized access to or disclosure of personally identifiable information, network security failures, and business interruption resulting from cyber events.
Analysis: The CGL increase from $5,000,000 to $10,000,000 per occurrence is above the typical range for utility-scale solar facilities, where $5,000,000 per occurrence is standard. However, higher limits are not uncommon in PPAs with large corporate counterparties, and the additional cost may be modest depending on the insurer's pricing. We should confirm with Fieldstone Risk Advisors LLC (broker) and the incumbent carriers (Commonwealth Mutual / Ridgeway Casualty Group) whether the increased limit is achievable within the existing program structure and what the incremental premium cost would be.
The cyber liability insurance requirement is unusual for a solar PPA. It appears to be driven by Meridian's sensitivity as a data center operator to cybersecurity risks. While a solar PV facility has a SCADA system and internet-connected monitoring equipment that could theoretically be subject to cyber intrusion, the risk profile is fundamentally different from a data center. The requirement may reflect Meridian's standard vendor insurance requirements rather than a tailored assessment of the risks specific to this PPA.
Assessment: MODERATE. We recommend discussing both changes with the client and with Fieldstone Risk Advisors LLC. If the CGL increase is achievable at a reasonable incremental cost, we are inclined to accept it. On the cyber insurance requirement, we recommend pushing back or, if Buyer insists, negotiating a lower limit (e.g., $2,000,000) and ensuring that the coverage scope is limited to cyber risks arising from the Facility's SCADA and operational technology systems, not the broader corporate network of Seller or CBR.
4.9 Indemnification (Article 13)
Seller's Form: Article 13 of the Seller's Form contained standard mutual indemnification provisions, under which each party agreed to indemnify the other against third-party claims arising from (a) the indemnifying party's breach of the PPA, (b) the indemnifying party's negligence or willful misconduct, and (c) the indemnifying party's violation of applicable law. The Seller's Form did not include a waiver of consequential damages.
Buyer's Redline: Buyer made two changes:
(a) Buyer expanded the indemnification to include an additional Seller-specific indemnity for "all losses, liabilities, claims, damages, costs, and expenses (including reasonable attorneys' fees) arising from or related to Seller's failure to maintain the Facility in compliance with all applicable laws, permits, licenses, and governmental approvals"; and
(b) Buyer added a mutual waiver of consequential damages: "In no event shall either Party be liable to the other Party for any special, indirect, incidental, consequential, or punitive damages of any kind (including lost profits, lost revenues, and loss of business opportunity), regardless of the form of action or the theory of liability, even if such Party has been advised of the possibility of such damages; provided, however, that this limitation shall not apply to (i) damages arising from a Party's willful misconduct or gross negligence, or (ii) damages arising from a breach of Article 17.8 (Confidentiality)."
Analysis: The expanded compliance indemnity in (a) is broad but largely duplicative of the existing indemnity for violations of applicable law. It could be interpreted as a strict liability standard for permit compliance (i.e., Seller indemnifies for any compliance failure, regardless of fault), whereas the existing general indemnity may require negligence or breach. We recommend accepting this indemnity with an express qualification that it applies only to compliance failures resulting from Seller's negligence or willful misconduct, not to strict liability for regulatory changes or reinterpretations beyond Seller's control.
The mutual waiver of consequential damages in (b) is favorable to Seller and is a provision that Seller would typically seek to include. Consequential damages (lost profits, lost revenues, loss of business opportunity) represent the most significant category of uncapped exposure in a 20-year PPA. By waiving consequential damages mutually, both parties are limited to direct damages, which significantly reduces Seller's tail risk. The carve-outs for willful misconduct and confidentiality breaches are standard and acceptable.
Assessment: MODERATE. Accept the mutual consequential damages waiver as written. Accept the compliance indemnity with a negligence/willful misconduct qualification. The consequential damages waiver should be highlighted to the client as a favorable development — it was not included in the Seller's Form and was added by Buyer, which suggests that Buyer's own risk management team recognizes the value of mutual limitation.
4.10 Term and Termination — Early Termination Fee (Article 15)
Seller's Form: The Seller's Form did not include a voluntary early termination mechanism outside of the default-based termination provisions. Under the Seller's Form, either party could terminate the PPA only upon (a) a material default by the other party that remained uncured after the applicable notice and cure period, (b) a change of control event (subject to the provisions of Article 8), (c) an extended Force Majeure event (subject to the provisions of Article 10), or (d) failure to achieve COD within the specified backstop period. Termination payments upon default were addressed in Section 15.3 (see Section 5.6 below for discussion of Buyer's changes to that provision).
Buyer's Redline: Buyer inserted a new Section 15.2(e) providing for a voluntary early termination right by either party, exercisable at any time after the fifth (5th) anniversary of the COD, upon twelve (12) months' prior written notice and payment of an early termination fee (the "ETF") equal to the lesser of:
(a) $10,000,000; or
(b) the net present value of the remaining contract payments for the balance of the PPA term, calculated using the then-current Contract Price, P50 generation estimates, and a discount rate of 7.0%.
Analysis: The concept of a voluntary early termination right with an ETF is not standard in utility-scale solar PPAs, but it is not unheard of in long-tenor CfDs, particularly where the counterparties recognize that market conditions may change materially over a 20-year period. The ETF concept provides both parties with a mechanism to exit the PPA without needing to engineer a default, which could have collateral consequences (credit rating impact, cross-default triggers, litigation risk). From Seller's perspective, the ETF concept is a double-edged sword:
• Benefit: If Buyer wishes to terminate (e.g., because Buyer no longer needs the renewable energy attributes, or because market prices have dropped significantly below the Contract Price), the ETF provides Seller with a lump-sum payment that can be used to prepay the Tralvendo facility and seek a replacement offtaker.
• Risk: If market prices increase significantly above the Contract Price, Buyer could exercise the ETF to escape a below-market contract, paying $10,000,000 to avoid potentially tens of millions of dollars in above-market payments over the remaining term. Similarly, if Seller's economics improve dramatically (e.g., due to ITC/PTC benefit capture and declining O&M costs), Seller might be tempted to exercise the ETF to recontract at a higher price, but the ETF cost and reputational risk may make this unattractive.
The $10,000,000 cap on the ETF is significant — it limits the early termination cost regardless of the remaining contract value, which could create perverse incentives in extreme market scenarios.
Assessment: MODERATE. The ETF concept requires careful review and financial modeling by Derek Engstrom. Specifically, we need to understand (i) the NPV of the remaining PPA payments at various points in the term (Year 5, Year 10, Year 15) under various market price scenarios, (ii) whether the $10,000,000 cap is sufficient to compensate the non-terminating party for lost value, and (iii) how the ETF interacts with the Tralvendo credit facility (which likely includes a prepayment premium or make-whole provision). The five-year lock-out period provides some protection, but the post-Year-5 optionality may be underpriced at $10,000,000. We recommend discussing the concept with the client and, if accepted in principle, proposing a higher cap (e.g., $15,000,000–$20,000,000) and a longer lock-out period (e.g., ten years rather than five).
5. Category C — Material / High Priority Changes
This section discusses the most significant substantive changes in the Buyer's Redline — those classified as Category C (Material / High Priority). Each of these issues requires client input, strategic assessment, and in most cases coordination with project-finance lenders and financial advisors.
5.1 Availability Guarantee (Article 6) — PRIORITY: HIGH
The availability guarantee is the most heavily negotiated section of the Buyer's Redline. Buyer's counsel made changes to each of the four key components of the availability framework: (i) the guaranteed threshold, (ii) the LD rate, (iii) the LD cap, and (iv) the termination trigger. These changes are discussed in turn below. Taken together, they represent a fundamental shift in the availability risk allocation and would materially increase Seller's financial exposure.
5.1.1 Guaranteed Availability Threshold
Seller's Form: Seller guaranteed that the Facility would achieve availability of ≥ 95.0% on a rolling twelve (12)-month basis, measured as Available Hours ÷ Period Hours × 100, excluding (a) Force Majeure hours, (b) Buyer-caused curtailment hours, and (c) scheduled maintenance hours (up to 200 hours per Contract Year).
Buyer's Redline: Buyer increased the guaranteed availability threshold to ≥ 97.0% on a rolling twelve (12)-month basis. The measurement methodology remains the same (Available Hours ÷ Period Hours × 100), but with the scheduled maintenance allowance reduced from 200 to 150 hours per Contract Year (as discussed in Section 4.4 above). All other exclusions (Force Majeure, Buyer-caused curtailment) remain unchanged.
Analysis: A 97.0% availability guarantee with only 150 hours of excluded maintenance is extremely aggressive for a 150 MWac ground-mounted single-axis tracking solar PV facility of the type and scale of the Saguaro Flats Project. To contextualize:
• Industry benchmarks: For utility-scale solar facilities in ERCOT, the industry standard for contractual availability guarantees is typically in the range of 95.0%–97.0%. While 97.0% is within this range, it represents the absolute upper end and is typically seen only in PPAs with well-established operators and facilities in regions with minimal grid congestion and favorable maintenance conditions.
• Maintenance window interaction: At 95.0% availability with 200 hours of maintenance excluded, the Facility has an effective "downtime budget" of approximately 438 hours per year (5.0% of 8,760 hours) plus 200 hours of excluded maintenance = 638 hours total. Under Buyer's proposal (97.0% with 150 hours), the total budget shrinks to approximately 263 hours (3.0% of 8,760) + 150 hours = 413 hours total — a reduction of approximately 35% in the total permissible downtime.
• P50 generation impact: At P50 annual generation of 350,000 MWh (per Heliograph Energy Consulting LLC), the 2.0 percentage-point increase in the threshold materially increases the risk of availability shortfalls. The P50 estimate assumes 95.0% availability; if the guarantee is set at 97.0%, the P50 estimate would need to be recalibrated to reflect the tighter operating parameters.
• Compounding risk: The combination of the higher threshold (97.0%) and the reduced maintenance allowance (150 hours) creates a compounding risk that is greater than the sum of the individual changes. This is particularly concerning given the Facility's location in West Texas, where high ambient temperatures, dust, and severe weather events (hail, thunderstorms) can cause equipment outages and necessitate unplanned maintenance.
Recommendation: Propose a compromise at 96.0% with 200 hours of scheduled maintenance retained. This is within the market range, provides Buyer with a meaningful improvement over the Seller's initial 95.0% position, and preserves an adequate maintenance and downtime budget. The 96.0% threshold should be the subject of a detailed client memorandum, including financial modeling by Derek Engstrom, and should be presented to Buyer as a reasoned compromise. If Buyer insists on 97.0%, it must be coupled with the full 200-hour maintenance allowance and a revised LD structure (see Sections 5.1.2–5.1.4 below).
5.1.2 Availability Liquidated Damages — Rate
Seller's Form: For each 1.0 percentage point that actual availability fell below the guaranteed availability threshold in any rolling twelve-month measurement period, Seller would pay Buyer an availability liquidated damages ("Availability LDs") amount equal to 0.50% of the trailing twelve months' revenue (the "T-12 Revenue"). At P50 generation (350,000 MWh) and the Year 1 Contract Price of $20.00/MWh, T-12 Revenue in Year 1 would be approximately $7,000,000, and the LD rate would be $7,000,000 × 0.50% = $35,000 per 1.0 percentage point of shortfall.
Buyer's Redline: Buyer increased the LD rate to 1.00% of T-12 Revenue per 1.0 percentage point of shortfall. At Year 1 T-12 Revenue of $7,000,000, the LD rate would be $7,000,000 × 1.00% = $70,000 per 1.0 percentage point of shortfall — double the Seller's proposed rate.
Analysis: The financial impact of the doubled LD rate is significant, particularly when combined with the higher guaranteed threshold. Consider the following hypothetical scenarios for Year 1:
As the table illustrates, at a hypothetical 93.0% availability (which is below industry average but not uncommon in years with significant weather events or equipment issues), Seller's exposure under Buyer's terms ($280,000) is four times the exposure under Seller's terms ($70,000). The disparity is driven by both the doubled LD rate and the fact that LD accrual begins at 97.0% rather than 95.0%.
Recommendation: Propose a compromise at 0.75% of T-12 Revenue per 1.0 percentage point of shortfall. This represents a 50% increase from Seller's initial position and demonstrates willingness to move on the LD rate while avoiding the full doubling proposed by Buyer. This issue should be addressed in the separate client memorandum on availability, together with financial modeling under P50 and P90 scenarios. Derek Engstrom should run DSCR sensitivity analysis at various LD rate levels.
5.1.3 Availability Liquidated Damages — Cap
Seller's Form: Total Availability LDs in any rolling twelve-month period were capped at 5.0% of T-12 Revenue. At Year 1 T-12 Revenue of approximately $7,000,000, the annual LD cap would be approximately $350,000.
Buyer's Redline: Buyer increased the annual LD cap to 10.0% of T-12 Revenue. At Year 1, this would result in an annual cap of approximately $700,000.
Analysis: An annual LD cap of $700,000 represents approximately 10% of expected annual revenue of $7,000,000 in Year 1. While the Contract Price escalates at 1.50% per annum from Year 6, the LD cap (expressed as a percentage of T-12 Revenue) would escalate proportionally, reaching approximately $963,000 by Year 20 (assuming P50 generation and cumulative escalation). The cumulative impact over the 20-year PPA term, under adverse availability scenarios, could be substantial.
More importantly, the annual LD cap must be evaluated in the context of the minimum Debt Service Coverage Ratio ("DSCR") covenant under the Tralvendo credit facility. The Tralvendo facility requires a minimum DSCR of 1.30x. At Year 1 revenues of $7,000,000 and estimated annual debt service of approximately $5,000,000 (based on an assumed 18-year amortization of the $108,000,000 facility at approximately 5.5% weighted average interest rate, net of estimated operating expenses of approximately $1,200,000), the projected DSCR is approximately 1.16x before any availability LDs. This suggests that the DSCR is already tight, and an annual LD exposure of $700,000 (Buyer's proposal) versus $350,000 (Seller's proposal) could be the difference between a DSCR covenant compliance and a covenant breach.
Note: The DSCR calculation above is illustrative and uses rough estimates. A precise calculation requires Derek Engstrom's financial model, which accounts for the actual amortization schedule, interest rate, operating expense budget, and tax equity considerations. The key point is that the LD cap level is a DSCR-sensitive variable.
Recommendation: Propose a compromise at 7.5% of T-12 Revenue. This represents the midpoint between the parties' positions and limits Seller's annual LD exposure to approximately $525,000 in Year 1. Flag the DSCR sensitivity for lender coordination with Helen Nakamura and Derek Engstrom. If the DSCR analysis shows that even 7.5% creates unacceptable covenant risk, we may need to hold at 5.0% or explore alternative structures (e.g., availability LDs payable on a deferred basis to smooth the cash flow impact).
5.1.4 Availability Termination Trigger
Seller's Form: Buyer could terminate the PPA if availability fell below 85.0% in any two (2) consecutive rolling twelve (12)-month periods, and Seller failed to cure the availability shortfall within a cure period of 180 days following Buyer's notice of the second consecutive below-threshold period.
Buyer's Redline: Buyer could terminate the PPA if availability fell below 90.0% in any single rolling twelve (12)-month period. No requirement for consecutive periods. Cure period reduced from 180 days to 90 days.
Analysis: Buyer's proposal is substantially more aggressive than the Seller's Form in three independent respects, each of which merits careful analysis: