PRIVILEGED AND CONFIDENTIAL ATTORNEY-CLIENT COMMUNICATION / ATTORNEY WORK PRODUCT
This memorandum is a privileged and confidential attorney-client communication and constitutes attorney work product. It is intended solely for the use of the addressees and other authorized representatives of Calloway-Briggs Renewables Inc. This memorandum is not intended for disclosure to, and should not be shared with, any third party without the prior written consent of Calderwood & Harkness LLP. Disclosure to any third party may result in a waiver of applicable privileges.
MEMORANDUM
TO: Rachel Muñoz, General Counsel, Calloway-Briggs Renewables Inc. Janet Okafor, SVP, Origination & Commercial, Calloway-Briggs Renewables Inc.
FROM: Brett Callahan, Lead Associate, Energy & Infrastructure, Calderwood & Harkness LLP Patricia Dunmore, Responsible Partner, Energy & Infrastructure, Calderwood & Harkness LLP
DATE: August 4, 2025
RE: Saguaro Flats Solar Project — Analysis of Buyer's Availability Guarantee Proposals (Power Purchase Agreement with Meridian DataCore Solutions Inc.)
Matter No.: 1015-00002
cc: David Stanton, Working Associate, Calderwood & Harkness LLP Helen Nakamura, Of Counsel, Project Finance, Calderwood & Harkness LLP
I. Executive Summary
The purpose of this memorandum is to analyze the availability guarantee proposals submitted by Meridian DataCore Solutions Inc. ("Buyer" or "Meridian") in Buyer's redline of the Power Purchase Agreement (the "PPA") received on August 1, 2025, from Hargrove & Linden LLP, counsel to Meridian, and to compare those proposals against the positions set forth in Seller's Form PPA circulated by our firm on July 14, 2025. "Seller" refers to Saguaro Flats Solar LLC, a Delaware limited liability company wholly owned by Calloway-Briggs Renewables Inc. ("CBR"). This memorandum is limited to the availability guarantee provisions; a separate memorandum addressing the change of control open items is forthcoming.
The PPA under negotiation is a twenty-year virtual (financial) power purchase agreement structured as a contract for differences for the output of the Saguaro Flats Solar Project (the "Project"), a 150 MWac / 195 MWdc ground-mounted single-axis tracking solar photovoltaic facility located in Pecos County, Texas. The PPA settles at the ERCOT West Hub. Based on a P50 annual generation forecast of 350,000 MWh and a blended average contract price of approximately $20.00/MWh, the aggregate nominal contract value over the twenty-year term is approximately $140,000,000.
The availability guarantee provisions are among the most commercially significant open items remaining in the PPA negotiation. Resolution of these provisions, along with the change of control provisions, is targeted for August 18, 2025, with PPA execution targeted for September 15, 2025. Timely resolution is critical because the lender group led by Tralvendo National Bank, N.A. (the "Administrative Agent" for the $108,000,000 construction-to-term loan facility) requires a bankability sign-off on the PPA as a condition precedent to construction loan closing, which is targeted for October 1, 2025.
Our analysis addresses four discrete components of the availability guarantee regime: (1) the guaranteed availability threshold, (2) the liquidated damages rate applicable to shortfalls below the threshold, (3) the cap on availability liquidated damages, and (4) the termination trigger for chronic underperformance. In each case, Buyer's redline proposes materially more aggressive positions than those set forth in Seller's Form PPA. Taken together, Buyer's proposals would significantly increase Seller's financial exposure, threaten the Project's ability to maintain the 1.30x minimum debt service coverage ratio ("DSCR") covenant under the credit agreement with Tralvendo, and create an unacceptably low bar for PPA termination.
We recommend the following compromise position, which we believe is defensible to both Buyer and the lender group, aligns with market practice for utility-scale solar PPAs in ERCOT, and preserves the Project's cash flow and PPA bankability:
• Guaranteed Availability Threshold: 96.0% on a rolling 12-month basis
• LD Rate: 0.75% of trailing 12-month PPA revenues per 1.0% shortfall below the guaranteed availability threshold
• LD Cap: 7.5% of trailing 12-month PPA revenues
• Termination Trigger: Buyer may terminate only if availability falls below 87.5% in two consecutive 12-month measurement periods, uncured
Lender bankability is a critical constraint throughout this analysis. The PPA is the sole revenue contract securing the $108,000,000 senior secured construction-to-term loan facility. The PPA must support a minimum 1.30x DSCR covenant, and the projected DSCR at P50 production and Year 1 pricing is only approximately 1.35x — providing a narrow cushion of approximately $260,000 in annual revenue. Availability LD payments reduce revenue available for debt service on a dollar-for-dollar basis. Accordingly, the availability guarantee provisions must be calibrated to avoid routine LD payments that erode the DSCR cushion.
Each of the foregoing recommendations and the analytical basis therefor is discussed in detail below.
II. Background and Deal Context
A. Parties and Project
Seller. The Seller under the PPA is Saguaro Flats Solar LLC, a Delaware limited liability company formed for the purpose of developing, constructing, owning, and operating the Project. Saguaro Flats Solar LLC is a wholly-owned, direct subsidiary of Calloway-Briggs Renewables Inc. ("CBR"), a Delaware corporation with its principal offices in Austin, Texas. CBR is the project sponsor and will provide the equity contribution for the Project.
Buyer. The Buyer under the PPA is Meridian DataCore Solutions Inc. ("Meridian"), a Delaware corporation publicly traded on the Nasdaq Stock Market under the ticker symbol "MDCS." Meridian is a large-scale data center operator headquartered in Phoenix, Arizona, with significant operations in Texas. Meridian is entering into the PPA as part of its corporate renewable energy procurement strategy to match its Texas data center load with contracted renewable generation. Meridian's counsel in this transaction is the firm of Hargrove & Linden LLP, with Evelyn Crumveth serving as lead partner and Ryan Matsuda serving as the primary associate on the deal.
Project. The Saguaro Flats Solar Project is a utility-scale ground-mounted solar photovoltaic generating facility with a nameplate capacity of 195 MWdc and an AC interconnection capacity of 150 MWac, resulting in a DC-to-AC ratio of approximately 1.30. The Project employs single-axis tracking technology, which maximizes energy capture by orienting the solar panels to follow the sun's east-west trajectory throughout the day. The Project is situated on approximately 1,400 acres of leased land located off FM Road 1776, approximately 12 miles southeast of Fort Stockton, in Pecos County, Texas 79735.
The Project will interconnect to the ERCOT transmission grid at the Ft. Stockton 345 kV Substation pursuant to the terms of a Large Generator Interconnection Agreement ("LGIA") executed on May 15, 2025. The transmission interconnection is being constructed by West Texas Wires LLC. The Project holds ERCOT interconnection queue position ERCOT-GI-2024-0437.
The engineering, procurement, and construction ("EPC") services for the Project are being performed by Sunbelt Power Construction LLC under a fixed-price turnkey EPC contract with a contract price of $142,500,000. The expected commercial operation date ("COD") is April 1, 2027. The PPA term will commence on COD and expire twenty years thereafter, on March 31, 2047.
B. PPA Economics
The PPA is structured as a virtual power purchase agreement, also commonly referred to as a financial PPA or contract for differences. Under this structure, there is no physical delivery of electricity from Seller to Buyer. Instead, the parties settle financially based on the difference between the fixed contract price and the floating ERCOT West Hub locational marginal price ("LMP") for each settlement interval. When the ERCOT West Hub LMP exceeds the contract price, Seller pays the difference to Buyer; when the contract price exceeds the LMP, Buyer pays the difference to Seller. This structure allows Buyer to obtain the economic benefit of fixed-price renewable energy without taking physical delivery, while Seller retains the ability to sell its energy and capacity into the ERCOT market.
The contract price under the PPA is $20.00/MWh, fixed for Years 1 through 5 of the PPA term (i.e., from COD through March 31, 2032). Beginning in Year 6 and continuing through the expiration of the PPA term, the contract price escalates at a rate of 1.50% per annum, compounded annually. The resulting contract prices at selected intervals are as follows:
The P50 annual generation forecast for the Project is 350,000 MWh per year, as determined by Heliograph Energy Consulting LLC in its independent solar resource assessment dated March 2025. Over the full twenty-year PPA term, the total contracted volume at P50 is approximately 7,000,000 MWh. Applying the blended average contract price across all twenty years to this total volume yields an aggregate nominal contract value of approximately $140,000,000, or an average annual contract value of approximately $7,000,000 per year.
It is important to note that the $7,000,000 average annual revenue figure is the critical input for purposes of calculating availability LDs and assessing DSCR impact throughout this memorandum. In the early years of the PPA, when the contract price is at the $20.00/MWh floor and before any escalation takes effect, annual PPA revenues at P50 are expected to be approximately $7,000,000 per year. This figure is used as the baseline for all illustrative LD calculations herein unless otherwise noted.
C. Project Finance Overlay
The Project is being financed with a senior secured construction-to-term loan facility in the aggregate principal amount of $108,000,000 (the "Credit Facility"). The Credit Facility is being provided by a syndicate of lenders with Tralvendo National Bank, N.A. (Dallas, Texas) serving as Administrative Agent. The lending syndicate is composed as follows:
Counsel to the lender group is Whitfield Stroval & Cade LLP, with Philip Thornton serving as lead partner. The primary business contact at Tralvendo for purposes of the PPA bankability review is Diane Roessler, Vice President, Renewable Energy Finance.
The total Project cost is approximately $154,300,000, consisting of the EPC contract price of $142,500,000 plus approximately $11,800,000 in soft costs (including development costs, land lease payments, interconnection costs, legal fees, insurance premiums, and initial reserve account funding). The Credit Facility represents approximately 70% of total Project costs, with the remaining 30% ($46,300,000) to be funded through equity contributions by CBR.
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 Credit Facility contains, among other financial covenants, a minimum DSCR covenant of 1.30x, measured on a trailing twelve-month basis commencing with the first full year of commercial operations.
The projected DSCR at P50 production levels and Year 1 contract pricing is approximately 1.35x. This projection is based on annual PPA revenues of approximately $7,000,000 and estimated annual debt service of approximately $5,200,000. The resulting DSCR cushion above the 1.30x minimum covenant is modest — approximately $260,000 in annual revenue. This narrow cushion means that any recurring reduction in net revenue available for debt service — including availability LD payments — has the potential to erode the DSCR below the covenant threshold.
The target construction loan closing date is October 1, 2025. As a condition precedent to construction loan closing, the lender group requires delivery of (a) an executed PPA in form and substance satisfactory to the Administrative Agent, (b) a PPA bankability opinion from Tralvendo's independent engineer, Gresham Engineering Advisors Inc., and (c) an executed Lender Consent Agreement (attached to the PPA as Exhibit F), pursuant to which Buyer consents to, among other things, the collateral assignment of Seller's interest in the PPA to the Administrative Agent as security for the Credit Facility. The timeline for resolution of the availability guarantee provisions is therefore driven in large part by the financing schedule.
D. Procedural Posture
The negotiation of the PPA has proceeded as follows:
• July 14, 2025: Calderwood & Harkness circulated Seller's Form PPA (the "First Draft PPA") to Hargrove & Linden LLP on behalf of Seller. The First Draft PPA contained Seller's initial positions on all material terms, including the availability guarantee provisions.
• August 1, 2025: Hargrove & Linden LLP delivered Buyer's redline of the First Draft PPA (the "August 1 Redline") on behalf of Meridian. The August 1 Redline contained extensive mark-ups to numerous provisions, including the availability guarantee, change of control, curtailment risk allocation, force majeure, and termination payment provisions.
• August 4, 2025 (today): Calderwood & Harkness has reviewed and catalogued all Buyer changes reflected in the August 1 Redline. This memorandum addresses the availability guarantee components only. A separate memorandum addressing the change of control provisions will follow under separate cover.
The parties have agreed to target resolution of the availability guarantee and change of control open items by August 18, 2025. CBR's lead commercial contact for this negotiation is Janet Okafor, SVP, Origination & Commercial. Meridian's lead commercial contact is believed to be Thomas Kwan, VP of Energy Procurement. PPA execution is targeted for September 15, 2025, in order to support the October 1, 2025, construction loan closing.
III. Side-by-Side Comparison of the Parties' Positions
Set forth below is a side-by-side comparison of the four availability guarantee components as proposed by Seller in the First Draft PPA and by Buyer in the August 1 Redline. Each component is addressed in further detail in Sections IV through VI of this memorandum.
A. Guaranteed Availability Threshold
Seller's Position (First Draft PPA): Seller proposes a guaranteed availability threshold of ≥ 95.0%, measured on a rolling 12-month basis.
Buyer's Position (August 1 Redline): Buyer proposes a guaranteed availability threshold of ≥ 97.0%, measured on a rolling 12-month basis.
Measurement Methodology: The parties are in agreement on the measurement methodology. Availability is calculated as Available Hours ÷ Period Hours × 100, expressed as a percentage. "Available Hours" is defined as the total number of hours in the measurement period during which the Project (or, more precisely, each generating unit comprising the Project, on a capacity-weighted basis) is available to generate and deliver energy to the ERCOT grid, regardless of whether actual generation occurs during those hours. "Period Hours" is defined as the total number of hours in the applicable rolling 12-month measurement period (8,760 hours in a non-leap year; 8,784 hours in a leap year).
Agreed Exclusions: Both parties agree that the following categories of hours are excluded from the calculation of Available Hours for purposes of measuring availability against the guaranteed threshold:
(a) Force Majeure hours — hours during which the Project is unavailable due to an event of Force Majeure as defined in the PPA;
(b) Curtailment hours — hours during which the Project's output is curtailed by the ERCOT grid operator or the applicable transmission service provider; and
(c) Scheduled maintenance — up to 200 hours per contract year of pre-approved scheduled maintenance downtime.
The 200-hour scheduled maintenance allowance is agreed in principle, although Seller may seek to expand this allowance to 250 hours as part of the overall compromise package, as discussed in Section VIII.E below.
B. Availability Liquidated Damages Rate
Seller's Position (First Draft PPA): Seller proposes an availability LD rate of 0.50% of trailing 12-month PPA revenues per 1.0% shortfall below the guaranteed availability threshold.
Illustrative Calculation (P50 / Year 1): Annual PPA revenue at P50 and Year 1 pricing = 350,000 MWh × $20.00/MWh = $7,000,000. LD per 1.0% shortfall = 0.50% × $7,000,000 = $35,000.
Buyer's Position (August 1 Redline): Buyer proposes an availability LD rate of 1.00% of trailing 12-month PPA revenues per 1.0% shortfall below the guaranteed availability threshold.
Illustrative Calculation (P50 / Year 1): LD per 1.0% shortfall = 1.00% × $7,000,000 = $70,000. Buyer's proposed rate is exactly double Seller's proposed rate.
C. Availability LD Cap
Seller's Position (First Draft PPA): Seller proposes a cap on availability liquidated damages of 5.0% of trailing 12-month PPA revenues.
Illustrative Cap Amount (P50 / Year 1): 5.0% × $7,000,000 = $350,000.
Buyer's Position (August 1 Redline): Buyer proposes a cap on availability liquidated damages of 10.0% of trailing 12-month PPA revenues.
Illustrative Cap Amount (P50 / Year 1): 10.0% × $7,000,000 = $700,000.
The difference between the two positions at Year 1 P50 revenues is $350,000 — a significant amount in the context of the Project's narrow DSCR cushion.
D. Termination Trigger for Chronic Underperformance
Seller's Position (First Draft PPA): Buyer may terminate the PPA (and receive a Termination Payment from Seller) only if the Project's availability falls below 85.0% in any two consecutive 12-month measurement periods, and the underperformance remains uncured at the end of a notice and cure period.
Buyer's Position (August 1 Redline): Buyer may terminate the PPA if the Project's availability falls below 90.0% in any single 12-month measurement period.
Key Differences: Buyer's proposal differs from Seller's position in two fundamental respects:
First, Buyer proposes a significantly higher availability threshold for triggering termination — 90.0% versus 85.0%. This higher threshold means that a smaller degree of underperformance is sufficient to put the PPA at risk of termination.
Second, and perhaps more critically, Buyer proposes a single-period trigger rather than a two-consecutive-period trigger. Under Seller's proposal, Buyer cannot terminate unless the Project underperforms in two consecutive measurement periods, providing Seller with a meaningful opportunity to identify and cure the source of the underperformance before facing a termination right. Under Buyer's proposal, a single bad year — even if preceded and followed by years of exemplary performance — could result in termination of a 20-year contract with substantial remaining value.
The combination of these two differences represents a substantially lower bar for PPA termination under Buyer's proposal compared to Seller's position. The gap between Buyer's proposed 97.0% guaranteed threshold and its proposed 90.0% termination trigger is only 7.0 percentage points. Under Seller's proposal, the gap between the 95.0% threshold and the 85.0% termination trigger is 10.0 percentage points, and the additional requirement of two consecutive periods of underperformance provides further protection.
The following table summarizes the parties' positions across all four components:
IV. Analysis of Buyer's Availability Threshold Proposal (97.0%)
A. Operational Feasibility
Buyer's proposed guaranteed availability threshold of 97.0% is operationally aggressive for a utility-scale solar photovoltaic project employing single-axis tracking technology in the West Texas climate. To understand why, it is useful to quantify the amount of allowable downtime under a 97.0% threshold.
A 97.0% availability requirement over a 12-month measurement period means that the Project must be available to generate for at least 97.0% of all Period Hours. In a standard non-leap year of 8,760 hours, 97.0% availability corresponds to a maximum of approximately 263 hours of total downtime (8,760 × 3.0% = 262.8 hours). Both parties have agreed that up to 200 hours of scheduled maintenance downtime per year are excluded from the availability calculation. After subtracting this 200-hour scheduled maintenance allowance, the PPA would permit only approximately 63 hours of unscheduled downtime per year (263 hours total downtime minus 200 hours scheduled maintenance exclusion). Sixty-three hours of unscheduled downtime per year equates to approximately 5.25 hours per month — an extraordinarily tight operating constraint for a complex, 150 MWac generating facility composed of thousands of individual solar modules, hundreds of string inverters, and an extensive single-axis tracking system with numerous mechanical and electrical components.
Single-axis tracker solar systems operating in the West Texas environment are subject to range sources of unscheduled downtime, including but not limited to the following:
• Weather-related downtime: West Texas is prone to severe weather events, including hailstorms, extreme heat events (which can cause inverter derating or thermal shutdown), and dust storms that can impair tracking system operation or trigger safety shutdowns. While some of these events may qualify as Force Majeure and be excluded from the availability calculation, many will fall below the severity threshold for Force Majeure and will be counted as downtime.
• Inverter failures: String inverters are among the most failure-prone components of a solar PV system. Replacement or repair of a failed inverter can take several days depending on parts availability and site access conditions. A project of this scale (150 MWac) will have hundreds of inverters, and statistical failure rates suggest that multiple inverter outages per year are probable.
• Transformer outages: Outages of the project substation transformer or pad-mounted transformers can take the entire facility or significant portions of it offline for extended periods, particularly if replacement transformers are required.
• Tracker malfunctions: Single-axis tracking systems have mechanical components (drive motors, bearings, linkages) that are subject to wear and failure. A tracker row malfunction may render a portion of the plant unavailable until repairs are completed.
• Communications and SCADA system outages: Interruptions in the plant's supervisory control and data acquisition system can affect the ability to dispatch or monitor the plant, potentially resulting in hours being counted as unavailable.
Industry data compiled from publicly available operating reports and from our firm's experience advising on O&M disputes and warranty claims for utility-scale solar projects in ERCOT indicates that unscheduled outages for utility-scale solar plants in the ERCOT region typically range from 150 to 300 hours per year in the early operating years (Years 1 through 5), with the range trending lower as systems mature and operators gain experience with the specific equipment and site conditions. Even in the best-performing years, unscheduled downtime of less than 100 hours would be considered exceptional, and unscheduled downtime of less than 63 hours would be highly unusual.
The practical effect of a 97.0% availability threshold, given the 200-hour scheduled maintenance allowance, is that Seller would be required to limit unscheduled downtime to approximately 63 hours per year — a level that is below the typical range of unscheduled outages for comparable facilities. In most operating years, actual availability is likely to fall below 97.0%, meaning that the guaranteed threshold would function not as a performance floor — a level below which something has gone meaningfully wrong — but rather as a routine payment obligation. The availability guarantee would, in effect, be converted from an exception-based mechanism into a recurring LD payment stream, which is not the intended purpose of an availability guarantee in a PPA of this nature.
B. Benchmarking Against Market Practice
Our firm has surveyed recent comparable solar PPAs executed in the ERCOT, SPP, and MISO organized markets, drawing on both Calderwood & Harkness's proprietary deal experience and publicly available data from regulatory filings, market reports, and industry publications. Based on this survey, we observe the following:
• The typical range for guaranteed availability thresholds in utility-scale solar PPAs is 95.0% to 97.0%, with the median at approximately 96.0%.
• PPAs that employ a 97.0% threshold generally involve one or more of the following distinguishing features: (i) newer-technology projects with higher expected reliability (e.g., projects using central inverters with built-in redundancy, or projects with advanced string-level monitoring and rapid-response O&M capabilities); (ii) projects with availability guarantees or warranties from tier-1 module OEMs or EPC contractors that backstop the PPA availability commitment; or (iii) PPAs with wider scheduled maintenance carve-outs (250 to 300 hours per year), which effectively provide greater operational flexibility to achieve the higher threshold.
• The 200-hour scheduled maintenance carve-out in the Saguaro Flats PPA is within the market range (typically 150 to 250 hours per year), but it sits at the lower end of that range. Pairing a 97.0% availability threshold with a 200-hour scheduled maintenance exclusion — as Buyer proposes — is more aggressive than is typical in comparable transactions.
From a lender perspective, Tralvendo and its independent engineer, Gresham Engineering Advisors Inc. ("Gresham"), will evaluate whether the guaranteed availability threshold is realistically achievable in light of the Project's specific technology configuration, West Texas site conditions, the proposed O&M plan, and the availability of spare parts and qualified maintenance personnel in the remote Pecos County area. An overly aggressive threshold that is likely to result in routine LD payments will be flagged by Gresham as a concern, because those LD payments reduce net revenue available for debt service and thereby pressure the DSCR.
C. Financial Impact on DSCR
The financial impact of Buyer's proposed 97.0% threshold on the Project's DSCR is best understood through a comparison of LD exposure at various levels of actual availability under both parties' proposals.
As noted in Section II.C, the projected DSCR at P50 production and Year 1 pricing, before any availability LD payments, is approximately 1.35x. This is calculated as follows:
Annual PPA revenue (P50): $7,000,000 Annual debt service: ~$5,200,000 DSCR: $7,000,000 ÷ $5,200,000 ≈ 1.35x
The DSCR cushion above the minimum 1.30x covenant is therefore:
Revenue at 1.30x: 1.30 × $5,200,000 = $6,760,000 Cushion: $7,000,000 − $6,760,000 = $240,000 (approximately $260,000 after accounting for rounding in the debt service estimate)
This $240,000–$260,000 cushion is the maximum amount of annual LD payments the Project can absorb before breaching the DSCR covenant, assuming P50 production levels and no other revenue reductions.
Under Buyer's combined proposals (97.0% threshold with a 1.00% LD rate), the LD exposure at various levels of actual availability is as follows:
• Actual availability = 95.0% (a realistic and indeed relatively good operating year): Shortfall = 97.0% − 95.0% = 2.0%. LD payment = 2.0 × $70,000 = $140,000. Adjusted DSCR ≈ ($7,000,000 − $140,000) ÷ $5,200,000 ≈ 1.32x. This is above the covenant but consumes more than half of the available cushion.
• Actual availability = 93.0% (a challenging but not extraordinary operating year): Shortfall = 97.0% − 93.0% = 4.0%. LD payment = 4.0 × $70,000 = $280,000. This amount exceeds the DSCR cushion. Adjusted DSCR ≈ ($7,000,000 − $280,000) ÷ $5,200,000 ≈ 1.29x — a breach of the 1.30x minimum covenant.
By contrast, under Seller's proposals (95.0% threshold with a 0.50% LD rate), the same actual availability levels produce markedly different results:
• Actual availability = 95.0%: No shortfall. No LD payment. DSCR remains at ~1.35x.
• Actual availability = 93.0%: Shortfall = 95.0% − 93.0% = 2.0%. LD payment = 2.0 × $35,000 = $70,000. Adjusted DSCR ≈ ($7,000,000 − $70,000) ÷ $5,200,000 ≈ 1.33x — comfortably above the covenant.
The difference is stark. Under Buyer's proposals, a year of 93.0% actual availability — which is well within the range of normal operating experience for utility-scale solar in West Texas — would trigger a DSCR covenant breach. Under Seller's proposals, that same level of performance leaves the DSCR comfortably above the covenant. This analysis alone demonstrates that Buyer's availability threshold proposal must be moderated.
V. Analysis of Buyer's LD Rate and Cap Proposals
A. LD Rate (1.00% vs. 0.50% per 1.0% Shortfall)
Buyer's proposed LD rate of 1.00% of trailing 12-month PPA revenues per 1.0% shortfall below the guaranteed availability threshold is at the upper end of the range observed in recent ERCOT solar PPAs. Based on our survey of comparable transactions, most recent solar PPAs in ERCOT employ LD rates in the range of 0.50% to 0.75% per 1.0% shortfall. A rate of 1.00% is occasionally seen, but typically in the context of projects with lower guaranteed thresholds (e.g., 95.0% or below), where the combination of a lower threshold and a higher per-unit LD rate is designed to produce a total LD exposure profile that is within market norms.
The critical issue with Buyer's LD rate proposal is not the rate in isolation, but its interaction with Buyer's proposed 97.0% availability threshold. The combination of a high threshold and a high rate creates a multiplicative effect that produces LD exposure significantly in excess of market norms. To illustrate:
Under Buyer's combined proposals (97.0% threshold / 1.00% rate): If actual availability is 94.0% — a perfectly normal operating year — the shortfall below the 97.0% threshold is 3.0%. The resulting LD payment is 3.0 × $70,000 = $210,000.
Under Seller's combined proposals (95.0% threshold / 0.50% rate): At 94.0% actual availability, the shortfall below the 95.0% threshold is only 1.0%. The resulting LD payment is 1.0 × $35,000 = $35,000.
The difference is sixfold ($210,000 versus $35,000) for the same level of actual plant performance. This disparity is driven entirely by the higher threshold and higher rate, not by any difference in actual performance.
From a conceptual standpoint, availability liquidated damages are intended to approximate the Buyer's actual economic harm from reduced plant availability. In a virtual PPA, the Buyer's economic harm from reduced availability is attenuated compared to a physical PPA, because the Buyer does not rely on the Project's physical output to serve its load; rather, the Buyer's interest is in the financial settlement stream, which is affected by the volume of energy generated and settled under the PPA but does not create a direct reliability exposure. An LD rate that significantly exceeds the Buyer's actual economic harm risks being characterized as a penalty rather than a genuine pre-estimate of damages, which could raise enforceability concerns under Texas law. While we do not believe that Buyer's proposed 1.00% rate would be deemed unenforceable standing alone, the principle of proportionality supports calibrating the rate to the Buyer's actual economic exposure.
We recommend an LD rate of 0.75% per 1.0% shortfall, which represents the midpoint between the parties' positions, falls squarely within the market range, and — when combined with the recommended 96.0% threshold — produces a total LD exposure profile that is proportionate to Buyer's economic harm and manageable from a DSCR perspective.
B. LD Cap (10.0% vs. 5.0% of Trailing 12-Month Revenue)
Buyer's proposed LD cap of 10.0% of trailing 12-month PPA revenues would limit Seller's maximum annual availability LD exposure to approximately $700,000 at Year 1 P50 revenue levels (10.0% × $7,000,000). While a cap serves the important function of limiting the tail risk of very poor availability performance, the level of the cap must be calibrated to ensure that the capped amount does not itself create unacceptable financial exposure for Seller.
At $700,000, Buyer's proposed cap significantly exceeds the Project's DSCR cushion of approximately $240,000–$260,000. If Seller were to pay LD amounts at or near the cap level, the Project's DSCR would fall well below the 1.30x covenant, triggering a default under the Credit Facility. This makes the cap, as proposed by Buyer, functionally illusory from a DSCR-protection standpoint — the Project would be in covenant default long before the cap is reached.
Seller's proposed cap of 5.0% of trailing 12-month revenues ($350,000 at Year 1 P50) is more conservative but would still consume most of the DSCR cushion if fully utilized. However, the 5.0% cap operates in tandem with Seller's lower 95.0% threshold and 0.50% LD rate, which make it unlikely that actual LD payments would approach the cap level in most operating years.
Based on our market survey, LD caps for availability guarantees in recent ERCOT solar PPAs range from 5.0% to 10.0% of trailing 12-month revenues, with an approximate median of 7.5%. We recommend a cap of 7.5%, which would limit Seller's maximum annual LD exposure to approximately $525,000 at Year 1 P50 revenues. While this amount exceeds the DSCR cushion, the cap is designed to operate as a ceiling in extreme scenarios, not a routine payment level. Under the recommended 96.0% threshold and 0.75% LD rate, actual LD payments at typical availability levels (93.0%–96.0%) would remain well below the cap. At the same time, a 7.5% cap provides Buyer with meaningful protection against sustained underperformance and demonstrates Seller's willingness to stand behind the Project's availability commitment.
The cap should serve as a meaningful protection for Seller against disproportionate financial exposure in a single measurement period, while still providing Buyer with adequate remedy for poor availability performance. The 7.5% level achieves this balance.
VI. Analysis of Buyer's Termination Trigger Proposal
A. Single-Period vs. Two-Consecutive-Period Requirement
The termination trigger for chronic underperformance is the most consequential of the four availability guarantee components, because it determines the circumstances under which Buyer can terminate a 20-year, $140,000,000 (nominal) contract and require Seller to pay a potentially massive Termination Payment. The stakes are qualitatively different from those associated with the LD threshold, rate, and cap, which govern periodic cash payments; the termination trigger implicates the existence of the PPA itself and, by extension, the viability of the entire Project financing.
Buyer proposes that it may terminate the PPA if the Project's availability falls below 90.0% in any single 12-month measurement period. Seller proposes that Buyer may terminate only if the Project's availability falls below 85.0% in two consecutive 12-month measurement periods, with the underperformance remaining uncured at the end of a notice and cure period.
The key concern with Buyer's single-period trigger is that it does not provide Seller with any opportunity to cure a transient availability problem before facing termination. A single catastrophic event — for example, an extended inverter replacement campaign necessitated by a recalled component, severe hail damage requiring replacement of a significant number of solar modules, or a transmission outage attributable to West Texas Wires LLC that does not qualify as Force Majeure under the PPA's definition — could cause the Project's availability to drop below 90.0% in a single measurement period, even if Seller promptly identifies and remedies the underlying condition and achieves strong availability performance in the following period.
Under a two-consecutive-period requirement, Seller would have the opportunity to demonstrate that the underperformance was isolated and has been corrected. The termination right would arise only if the Project fails to meet the threshold in both the initial bad year and the subsequent year — indicating a chronic, systemic problem rather than an isolated event. This cure-opportunity structure is standard in project finance transactions and is widely recognized as an appropriate balance between protecting the offtaker from persistent underperformance and protecting the project owner (and its lenders) from the loss of a long-term revenue contract based on a single anomalous period.
Buyer's proposed 90.0% threshold is itself problematic in combination with Buyer's proposed 97.0% guaranteed availability threshold. The band between the guaranteed threshold (97.0%) and the termination trigger (90.0%) is only 7.0 percentage points. This means that once the Project's availability falls below 97.0%, it enters the LD zone, and once it falls only an additional 7.0 percentage points, the Buyer has the right to terminate the entire PPA. By contrast, under Seller's proposal, the band between the guaranteed threshold (95.0%) and the termination trigger (85.0%) is 10.0 percentage points, and the two-consecutive-period requirement provides an additional structural buffer. The narrow band under Buyer's proposal, combined with the single-period trigger, creates an unacceptably thin margin between "paying modest LDs" and "losing the contract."
B. Termination Payment Implications
The financial consequences of a Buyer termination for chronic underperformance are potentially enormous. Under the PPA, if Buyer exercises a termination right for chronic unavailability, Seller is required to pay a Termination Payment to Buyer. The Termination Payment is generally calculated as the present value of the Buyer's lost contract benefit over the remaining term of the PPA, taking into account the difference between the fixed contract price and the then-prevailing market price for comparable renewable energy, discounted at an agreed-upon rate.
Given the 20-year term of the PPA, a Termination Payment could be substantial — potentially in the range of $20,000,000 to $50,000,000 or more, depending on the discount rate applied, the number of years remaining in the PPA term at the time of termination, and the replacement cost for comparable contracted renewable energy at the time of termination. The range is wide because the Termination Payment is sensitive to market conditions at the time of termination, which cannot be predicted with confidence over a multi-decade horizon.
A single-period termination trigger at 90.0% amplifies this risk disproportionately. Under such a trigger, a single year of poor performance — caused by events that may be largely beyond Seller's control and that may never recur — could expose Seller to a Termination Payment obligation of tens of millions of dollars. This risk is fundamentally inconsistent with the nature of the availability guarantee, which is intended to address chronic, systemic underperformance, not isolated incidents.
From the lender perspective, a forced termination of the PPA would constitute an event of default under the Credit Agreement with Tralvendo. The PPA is the sole revenue contract supporting the Credit Facility, and its termination would leave the lender group without a contracted revenue stream to service the $108,000,000 of outstanding debt. The lenders would face the prospect of foreclosing on a solar project without a PPA — a deeply unattractive outcome. The lender group will not accept a termination trigger structure that creates a meaningful risk of PPA loss from a single bad operating year.
C. Interaction with Force Majeure and Curtailment Exclusions
As noted in Section III.A, both parties agree that Force Majeure hours and curtailment hours are excluded from the availability calculation. However, the exclusion of these hours from the availability measurement operates only to the extent that the relevant downtime actually qualifies under the PPA's definitions of Force Majeure and curtailment. Definitional disputes around these concepts are common in PPA administration and can have a material impact on the availability calculation.
For example, the following types of events frequently give rise to disputes regarding whether the resulting downtime constitutes Force Majeure or is otherwise excluded from the availability calculation:
• Extreme heat events: Ambient temperatures in Pecos County regularly exceed 105°F during summer months, which can cause inverter thermal derating or shutdown. Whether an extreme heat event constitutes Force Majeure depends on the specific temperature threshold and duration criteria set forth in the PPA's definition — a matter still under negotiation.
• Grid reliability events: ERCOT has periodically issued Emergency Energy Alerts and other reliability directives that affect generator operations. Whether compliance with such directives constitutes curtailment (excluded) or simply a generator outage (included in downtime) may be contested.
• Transmission outages: Outages on the interconnection facilities owned by West Texas Wires LLC may render the Project unable to deliver energy, but the characterization of such outages as Force Majeure, curtailment, or Seller-caused downtime may be subject to dispute.
To the extent that hours associated with these types of events are not excluded from the availability calculation — either because they do not fall within the PPA's definitions or because the parties disagree on their characterization — they will count toward downtime and reduce measured availability. The stricter Buyer's termination trigger is, the more important it becomes that the Force Majeure and curtailment exclusions are drafted broadly enough to capture these categories of events. The analysis in this memorandum assumes that the Force Majeure and curtailment definitions ultimately agreed upon in the PPA will be reasonably broad, but we flag this interaction as a significant drafting consideration that will need to be addressed in the Second Draft PPA.
VII. Lender Bankability Assessment
A. Tralvendo's Expected Position
As discussed in Section II.C, the PPA is the sole revenue contract supporting the $108,000,000 Credit Facility, and the lender group led by Tralvendo National Bank, N.A. requires a bankability sign-off on the PPA as a condition precedent to construction loan closing. The availability guarantee provisions are among the most closely scrutinized provisions in a solar PPA bankability review, because they directly affect the predictability and stability of the revenue stream available to service debt.
The bankability assessment will involve two parallel workstreams. First, Tralvendo's independent engineer, Gresham Engineering Advisors Inc. ("Gresham"), will evaluate whether the guaranteed availability level is achievable in light of the Project's specific technology configuration (single-axis trackers with string inverters), the West Texas site conditions (high irradiance but also high heat, dust, and severe weather exposure), the proposed O&M plan (to be provided by Sunbelt Power Construction LLC under a separate O&M agreement), and the availability of qualified maintenance personnel and spare parts in the Pecos County area. If Gresham concludes that the guaranteed availability threshold is set at a level that is unlikely to be consistently achieved, Gresham will flag this as a risk factor in its independent engineer's report, which could jeopardize the lender group's willingness to close.
Second, Tralvendo's credit team will model the projected DSCR under various availability scenarios to determine whether the PPA availability provisions, including the LD exposure associated with potential shortfalls, are consistent with maintaining the 1.30x minimum DSCR covenant. The key lender concern is straightforward: availability LD payments reduce revenue available for debt service on a dollar-for-dollar basis; if the guaranteed threshold is set too high, projected LD exposure at median unscheduled outage levels erodes the DSCR below the covenant threshold, and the PPA becomes unbankable.
Based on our experience with Tralvendo and comparable lender groups in solar project financings, and based on preliminary discussions between Helen Nakamura (Of Counsel, Project Finance, Calderwood & Harkness) and Philip Thornton (Whitfield Stroval & Cade LLP, lender's counsel), we expect the following lender positions:
• Tralvendo will likely resist a guaranteed availability threshold of 97.0% combined with a 1.00% LD rate and a 10.0% cap, because the expected LD payments at median unscheduled outage levels (150–300 hours per year) would consume the DSCR cushion and, in poor-availability years, breach the 1.30x minimum covenant.
• The single-period termination trigger at 90.0% is likely unacceptable to the lender group under any scenario, because it creates a risk of PPA loss from a single bad operating year. PPA loss would constitute a default under the Credit Agreement and could result in foreclosure on the Project. Lenders universally require a two-consecutive-period (or longer) termination trigger structure to protect against this risk.
• A 96.0% threshold with a 0.75% LD rate and a 7.5% cap, combined with a two-consecutive-period termination trigger at 87.5%, is more likely to receive lender approval, provided that Gresham confirms the achievability of the 96.0% threshold and the sensitivity analysis demonstrates adequate DSCR protection.
B. Impact on Projected DSCR — Sensitivity Analysis
To quantify the DSCR impact of the various availability guarantee proposals, we have prepared the following sensitivity analysis, modeling LD payments and resulting DSCRs at various levels of actual availability under four scenarios. All calculations assume P50 annual generation (350,000 MWh), Year 1 contract pricing ($20.00/MWh), annual PPA revenue of $7,000,000, and annual debt service of approximately $5,200,000. The base case DSCR (no LDs) is approximately 1.35x.
Scenario 1 — Seller's Positions (95.0% threshold / 0.50% rate / 5.0% cap):
Scenario 2 — Buyer's Positions (97.0% threshold / 1.00% rate / 10.0% cap):
Scenario 3 — Buyer's Positions at Worst Case (Cap Reached):
Under Buyer's proposals, the LD cap of 10.0% ($700,000) would be reached at a shortfall of 10.0% (i.e., actual availability of 87.0%). At the cap level, net revenue would be $6,300,000, and the DSCR would be approximately 1.21x — well below the 1.30x covenant. However, as shown in Scenario 2, the DSCR breach occurs much earlier, at approximately 93.0% actual availability, long before the cap is reached.
Scenario 4 — Recommended Compromise (96.0% threshold / 0.75% rate / 7.5% cap):
Under the recommended compromise, the DSCR remains above the 1.30x covenant at all availability levels down to approximately 91.5%. This provides a comfortable margin under normal operating conditions (where actual availability is expected to be in the 93.0%–96.0% range) and maintains the DSCR above covenant even in a moderately poor-availability year. The covenant would be breached only in years with actual availability below approximately 91.5% — well below the expected operating range and well below the recommended 87.5% termination trigger. This relationship is appropriate: the LD mechanism should produce manageable payments in the expected operating range, and the termination trigger should be set at a level indicating systemic failure rather than routine underperformance.
C. Dialogue with Lender's Counsel
Helen Nakamura (Of Counsel, Project Finance) is coordinating directly with Philip Thornton at Whitfield Stroval & Cade LLP (lender's counsel) and with Diane Roessler at Tralvendo National Bank regarding the PPA bankability review. Ms. Nakamura has advised Mr. Thornton that the availability guarantee provisions are under active negotiation and that we expect to provide an updated PPA term summary reflecting the negotiated availability provisions once they are settled.
We anticipate providing Tralvendo with a detailed term summary and sensitivity analysis, substantially in the form set forth in Section VII.B above, once the availability guarantee provisions have been agreed between Seller and Buyer. The sensitivity analysis will be accompanied by a narrative explanation of the negotiation history and the rationale for the agreed terms.
Lender consent to the PPA, and execution of the Lender Consent Agreement (attached to the PPA as Exhibit F), are conditions precedent to both PPA execution and construction loan closing. The Lender Consent Agreement provides, among other things, for (a) Buyer's consent to the collateral assignment of Seller's interest in the PPA to the Administrative Agent, (b) Buyer's agreement to provide copies of default notices to the Administrative Agent and to allow a cure period for the Administrative Agent to cure Seller defaults, and (c) Buyer's agreement that any termination of the PPA will not be effective until the Administrative Agent has had an opportunity to exercise its step-in rights. These protections are standard in project finance transactions and are essential to the bankability of the PPA.
The timeline for lender review is tight. Assuming the availability guarantee provisions are settled by August 18, 2025, and the Second Draft PPA incorporating the agreed terms is circulated to Buyer's counsel on approximately August 11, 2025, we would expect to provide the PPA term summary to Tralvendo for bankability review in late August 2025, with Gresham's independent engineer assessment to be completed in early-to-mid September 2025, in time for PPA execution on September 15, 2025, and construction loan closing on October 1, 2025.
VIII. Recommended Compromise Position
Based on the analysis set forth in Sections IV through VII, we recommend the following compromise positions on each of the four availability guarantee components. These recommendations are designed to achieve a balanced outcome that is defensible to Buyer, acceptable to the Tralvendo lender group, consistent with market practice for utility-scale solar PPAs in ERCOT, and protective of Seller's cash flow and DSCR compliance.
A. Availability Threshold: 96.0%
We recommend that Seller propose a guaranteed availability threshold of 96.0% on a rolling 12-month basis. This represents a meaningful movement from Seller's opening position of 95.0% and splits the difference with Buyer's proposed 97.0%. The rationale for this recommendation is as follows:
Market alignment. A 96.0% threshold aligns with the approximate median of guaranteed availability thresholds observed in recent comparable solar PPAs in ERCOT, SPP, and MISO. It is neither aggressively low (which would undermine Buyer's confidence in the Project's operating commitment) nor unrealistically high (which would convert the guarantee into a routine payment obligation).
Operational achievability. A 96.0% threshold allows approximately 350 hours of total downtime per year (8,760 hours × 4.0% = 350 hours). After subtracting the agreed 200-hour scheduled maintenance allowance, this leaves approximately 150 hours of allowable unscheduled downtime per year. Based on industry data for comparable facilities in the ERCOT region, 150 hours of annual unscheduled downtime is an achievable target for a well-maintained single-axis tracker solar project, though it requires disciplined O&M practices and adequate spare parts availability. The 96.0% threshold thus serves its intended function as a meaningful performance floor — achievable with competent management, but requiring genuine attention to maintenance and operations.
DSCR protection. As demonstrated in the sensitivity analysis in Section VII.B (Scenario 4), a 96.0% threshold combined with the recommended 0.75% LD rate produces LD exposure that is manageable from a DSCR perspective across the expected range of actual availability levels.
Good-faith negotiation posture. Moving from 95.0% to 96.0% represents a full one-percentage-point concession by Seller — a significant movement that demonstrates good-faith engagement with Buyer's concerns about plant availability. This concession should be presented as part of a package that includes the other recommended positions on LD rate, LD cap, and termination trigger.
Bankability. A 96.0% threshold should be bankable from Tralvendo's perspective, subject to confirmation by Gresham Engineering Advisors Inc. that the threshold is consistent with their independent assessment of the Project's expected availability given the specific technology, site conditions, and O&M plan.
B. LD Rate: 0.75% of Trailing 12-Month Revenue per 1.0% Shortfall
We recommend that Seller propose an LD rate of 0.75% of trailing 12-month PPA revenues per 1.0% shortfall below the guaranteed availability threshold. This represents the precise midpoint between Seller's proposed 0.50% and Buyer's proposed 1.00%.
Illustrative calculation at P50 / Year 1: 0.75% × $7,000,000 = $52,500 per 1.0% shortfall below the 96.0% threshold.
The 0.75% rate is within the market range for ERCOT solar PPAs (0.50%–0.75% represents the most common range, with 1.00% at the upper boundary). The rate is proportionate to Buyer's actual economic harm from reduced availability in a virtual PPA structure and produces manageable LD payments at typical shortfall levels. A 2.0% shortfall (actual availability of 94.0%) would result in LD payments of $105,000 — significant enough to incentivize strong O&M performance, but not so large as to threaten DSCR compliance.
C. LD Cap: 7.5% of Trailing 12-Month Revenue
We recommend that Seller propose an LD cap of 7.5% of trailing 12-month PPA revenues, which represents the midpoint of Seller's proposed 5.0% and Buyer's proposed 10.0%.
Illustrative cap amount at P50 / Year 1: 7.5% × $7,000,000 = $525,000.
At the cap level of $525,000, the Project's DSCR would be approximately ($7,000,000 − $525,000) ÷ $5,200,000 ≈ 1.25x — below the 1.30x covenant. However, the cap is designed as a ceiling for extreme scenarios, not a target or expected payment level. Under the recommended 96.0% threshold and 0.75% LD rate, actual LD payments would approach the cap only if availability fell to approximately 86.0% — a catastrophic level that would likely already be in the zone of the termination trigger and well outside the range of normal operations. In the expected operating range of 93.0%–96.0%, LD payments would remain well below the cap and within the DSCR cushion.
The 7.5% cap provides Buyer with meaningful protection against sustained underperformance while limiting Seller's maximum annual exposure to a level that, while significant, is not disproportionate to the contract economics. The cap level of $525,000 represents approximately 7.5% of annual revenues and approximately 3.4% of annual debt service — a material but manageable exposure.
D. Termination Trigger: < 87.5% in Two Consecutive 12-Month Periods
We recommend that Seller propose a termination trigger set at an availability threshold of 87.5%, measured over two consecutive 12-month measurement periods, with an uncured condition requirement. This recommendation retains the two-consecutive-period structure from Seller's opening position while raising the threshold from 85.0% to 87.5% as a meaningful concession toward Buyer's proposed 90.0%.
Two-consecutive-period requirement. Retaining the two-consecutive-period structure is essential from both Seller's and the lenders' perspective. As discussed in Section VI.A, a single-period trigger creates an unacceptable risk that a one-time catastrophic event could result in the loss of a 20-year PPA with potentially tens of millions of dollars in remaining value. The two-consecutive-period requirement provides Seller with a cure opportunity and ensures that termination is reserved for cases of chronic, systemic underperformance — not isolated incidents.
87.5% threshold. Raising the termination trigger threshold from 85.0% to 87.5% is a meaningful concession that narrows the gap between the parties' positions. Buyer's proposal of 90.0% is aggressive, particularly in combination with a single-period trigger. However, moving from 85.0% to 87.5% demonstrates Seller's willingness to provide Buyer with a more protective exit right in the event of persistent poor performance, while still maintaining a workable band between the guaranteed threshold (96.0%) and the termination trigger (87.5%) of 8.5 percentage points. This band is sufficient to allow the LD mechanism to operate over a reasonable range of underperformance before the more drastic termination remedy becomes available.
Lender acceptability. A two-consecutive-period termination trigger at 87.5% is more likely to be acceptable to Tralvendo and the syndicate lenders than Buyer's single-period trigger at 90.0%. The two-period requirement reduces the probability of PPA loss from any single operating year, and the 87.5% threshold is low enough that actual availability would need to be severely impaired for two full years before the termination right could arise — a level of underperformance that would strongly suggest a fundamental problem with the Project rather than a transient condition.
E. Additional Recommendations
In addition to the four core availability guarantee components discussed above, we recommend the following supplementary measures to strengthen Seller's negotiating position and manage risk:
1. Expand the Scheduled Maintenance Exclusion. Seller should propose expanding the agreed scheduled maintenance exclusion from 200 hours per year to 250 hours per year. This expansion would partially offset the impact of the higher 96.0% guaranteed threshold by providing additional operational flexibility for planned maintenance activities. The effective allowable unscheduled downtime under a 96.0% threshold with a 250-hour maintenance exclusion would be approximately 100 hours (350 total downtime hours minus 250 scheduled maintenance hours), compared to approximately 150 hours under the current 200-hour exclusion. While this reduces the unscheduled downtime allowance, the expanded scheduled maintenance exclusion gives the O&M team greater flexibility to perform proactive preventive maintenance, which in turn reduces the likelihood of unscheduled outages. The net effect on Buyer's economics is negligible — the scheduled maintenance exclusion applies to planned, disclosed downtime, not to unexpected failures — and it improves the practical achievability of the 96.0% threshold.
2. Sole and Exclusive Remedy Provision. Seller should propose adding an explicit provision to the PPA stating that availability liquidated damages are the Buyer's sole and exclusive remedy for availability shortfalls below the guaranteed threshold but above the termination trigger threshold. This provision is important to prevent Buyer from claiming additional damages (whether compensatory, consequential, or otherwise) on top of the contractually agreed LD payments for the same shortfall. Without a sole-and-exclusive-remedy clause, Buyer could potentially argue that the LD payments do not fully compensate it for the economic harm caused by reduced availability and seek supplemental damages. A well-drafted exclusive remedy provision eliminates this risk and provides certainty to both parties regarding the financial consequences of availability shortfalls.
3. Broad Force Majeure and Curtailment Definitions. As discussed in Section VI.C, the higher the availability threshold and the lower the termination trigger, the more critical it becomes that the Force Majeure definition and the curt